Title 49—Transportation--Volume 1
PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS
§ 192.1   What is the scope of this part?
(a) This part prescribes minimum safety requirements for pipeline facilities and the transportation of gas, including pipeline facilities and the transportation of gas within the limits of the outer continental shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331).
(b) This part does not apply to—
(1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are produced or where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream;
(2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters without first connecting to a transporting operator's facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS may petition the Administrator, or designee, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9;
(3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator;
(4) Onshore gathering of gas—
(i) Through a pipeline that operates at less than 0 psig (0 kPa);
(ii) Through a pipeline that is not a regulated onshore gathering line (as determined in § 192.8); and
(iii) Within inlets of the Gulf of America, except for the requirements in § 192.612; or
(5) Any pipeline system that transports only petroleum gas or petroleum gas/air mixtures to—
(i) Fewer than 10 customers, if no portion of the system is located in a public place; or
(ii) A single customer, if the system is located entirely on the customer's premises (no matter if a portion of the system is located in a public place).
§ 192.3   Definitions.
As used in this part:
Abandoned means permanently removed from service.
Active corrosion means continuing corrosion that, unless controlled, could result in a condition that is detrimental to public safety.
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters.
Close interval survey means a series of closely and properly spaced pipe-to-electrolyte potential measurements taken over the pipe to assess the adequacy of cathodic protection or to identify locations where a current may be leaving the pipeline that may cause corrosion and for the purpose of quantifying voltage (IR) drops other than those across the structure electrolyte boundary, such as when performed as a current interrupted, depolarized, or native survey.
Composite materials means materials used to make pipe or components manufactured with a combination of either steel and/or plastic and with a reinforcing material to maintain its circumferential or longitudinal strength.
Control room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility.
Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility.
Customer meter means the meter that measures the transfer of gas from an operator to a consumer.
Distribution center means the initial point where gas enters piping used primarily to deliver gas to customers who purchase it for consumption, as opposed to customers who purchase it for resale, for example:
(1) At a metering location;
(2) A pressure reduction location; or
(3) Where there is a reduction in the volume of gas, such as a lateral off a transmission line.
Distribution line means a pipeline other than a gathering or transmission line.
Dry gas or dry natural gas means gas above its dew point and without condensed liquids.
Electrical survey means a series of closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline.
Engineering critical assessment (ECA) means a documented analytical procedure based on fracture mechanics principles, relevant material properties (mechanical and fracture resistance properties), operating history, operational environment, in-service degradation, possible failure mechanisms, initial and final defect sizes, and usage of future operating and maintenance procedures to determine the maximum tolerable sizes for imperfections based upon the pipeline segment maximum allowable operating pressure.
Entirely replaced onshore transmission pipeline segments means, for the purposes of §§ 192.179 and 192.634, where 2 or more miles, in the aggregate, of onshore transmission pipeline have been replaced within any 5 contiguous miles of pipeline within any 24-month period. This definition does not apply to any gathering line.
Exposed underwater pipeline means an underwater pipeline where the top of the pipe protrudes above the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from mean low water.
Gas means natural gas, flammable gas, or gas which is toxic or corrosive.
Gathering line means a pipeline that transports gas from a current production facility to a transmission line or main.
Gulf of America and its inlets means the waters from the mean high water mark of the coast of the Gulf of America and its inlets open to the sea (excluding rivers, tidal marshes, lakes, and canals) seaward to include the territorial sea and Outer Continental Shelf to a depth of 15 feet (4.6 meters), as measured from the mean low water.
Hard spot means an area on steel pipe material with a minimum dimension greater than two inches (50.8 mm) in any direction and hardness greater than or equal to Rockwell 35 HRC (Brinell 327 HB or Vickers 345 HV 10 ).
Hazard to navigation means, for the purposes of this part, a pipeline where the top of the pipe is less than 12 inches (305 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from the mean low water.
High-pressure distribution system means a distribution system in which the gas pressure in the main is higher than the pressure provided to the customer.
In-line inspection (ILI) means an inspection of a pipeline from the interior of the pipe using an inspection tool also called intelligent or smart pigging. This definition includes tethered and self-propelled inspection tools.
In-line inspection tool or instrumented internal inspection device means an instrumented device or vehicle that uses a non-destructive testing technique to inspect the pipeline from the inside in order to identify and characterize flaws to analyze pipeline integrity; also known as an intelligent or smart pig.
Line section means a continuous run of transmission line between adjacent compressor stations, between a compressor station and storage facilities, between a compressor station and a block valve, or between adjacent block valves.
Listed specification means a specification listed in section I of appendix B of this part.
Low-pressure distribution system means a distribution system in which the gas pressure in the main is substantially the same as the pressure provided to the customer.
Main means a distribution line that serves as a common source of supply for more than one service line.
Master Meter System means a pipeline system for distributing gas within, but not limited to, a definable area (such as a mobile home park, housing project, or apartment complex) where the operator purchases metered gas from an outside source for resale through a gas distribution pipeline system. The gas distribution pipeline system supplies the ultimate consumer who either purchases the gas directly through a meter or by other means, such as by rents.
Maximum actual operating pressure means the maximum pressure that occurs during normal operations over a period of 1 year.
Maximum allowable operating pressure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this part.
Moderate consequence area means:
(1) An onshore area that is within a potential impact circle, as defined in § 192.903, containing either:
(i) Five or more buildings intended for human occupancy; or
(ii) Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, as defined in the Federal Highway Administration's Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1 (see: https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classifications/fcauab.pdf ), and that does not meet the definition of high consequence area, as defined in § 192.903.
(2) The length of the moderate consequence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle containing either 5 or more buildings intended for human occupancy; or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, to the outermost edge of the last contiguous potential impact circle that contains either 5 or more buildings intended for human occupancy, or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes.
Municipality means a city, county, or any other political subdivision of a State.
Notification of potential rupture means the notification to, or observation by, an operator of indicia identified in § 192.635 of a potential unintentional or uncontrolled release of a large volume of gas from a pipeline. This definition does not apply to any gathering line.
Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters.
Operator means a person who engages in the transportation of gas.
Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof.
Petroleum gas means propane, propylene, butane, (normal butane or isobutanes), and butylene (including isomers), or mixtures composed predominantly of these gases, having a vapor pressure not exceeding 208 psi (1434 kPa) gage at 100 °F (38 °C).
Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders.
Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
Pipeline environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion.
Pipeline facility means new and existing pipelines, rights-of-way, and any equipment, facility, or building used in the transportation of gas or in the treatment of gas during the course of transportation.
Rupture-mitigation valve (RMV) means an automatic shut-off valve (ASV) or a remote-control valve (RCV) that a pipeline operator uses to minimize the volume of gas released from the pipeline and to mitigate the consequences of a rupture. This definition does not apply to any gathering line.
Service line means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line ends at the outlet of the customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection to customer piping if there is no meter.
Service regulator means the device on a service line that controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer or multiple customers through a meter header or manifold.
SMYS means specified minimum yield strength is:
(1) For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification; or
(2) For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with § 192.107(b).
State means each of the several States, the District of Columbia, and the Commonwealth of Puerto Rico.
Supervisory Control and Data Acquisition (SCADA) system means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility.
Transmission line means a pipeline or connected series of pipelines, other than a gathering line, that:
(1) Transports gas from a gathering pipeline or storage facility to a distribution center, storage facility, or large volume customer that is not down-stream from a distribution center;
(2) Has an MAOP of 20 percent or more of SMYS;
(3) Transports gas within a storage field; or
(4) Is voluntarily designated by the operator as a transmission pipeline.
Note 1 to transmission line. A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.
Transportation of gas means the gathering, transmission, or distribution of gas by pipeline or the storage of gas, in or affecting interstate or foreign commerce.
Underground natural gas storage facility ( UNGSF) means a gas pipeline facility that stores natural gas underground incidental to the transportation of natural gas, including:
(1)(i) A depleted hydrocarbon reservoir;
(ii) An aquifer reservoir; or
(iii) A solution-mined salt cavern.
(2) In addition to the reservoir or cavern, a UNGSF includes injection, withdrawal, monitoring, and observation wells; wellbores and downhole components; wellheads and associated wellhead piping; wing-valve assemblies that isolate the wellhead from connected piping beyond the wing-valve assemblies; and any other equipment, facility, right-of-way, or building used in the underground storage of natural gas.
Weak link means a device or method used when pulling polyethylene pipe, typically through methods such as horizontal directional drilling, to ensure that damage will not occur to the pipeline by exceeding the maximum tensile stresses allowed.
Welder means a person who performs manual or semi-automatic welding.
Welding operator means a person who operates machine or automatic welding equipment.
Wrinkle bend means a bend in the pipe that:
(1) Was formed in the field during construction such that the inside radius of the bend has one or more ripples with:
(i) An amplitude greater than or equal to 1.5 times the wall thickness of the pipe, measured from peak to valley of the ripple; or
(ii) With ripples less than 1.5 times the wall thickness of the pipe and with a wrinkle length (peak to peak) to wrinkle height (peak to valley) ratio under 12.
(2)(i) If the length of the wrinkle bend cannot be reliably determined, then wrinkle bend means a bend in the pipe where (h/D)*100 exceeds 2 when S is less than 37,000 psi (255 MPa), where (h/D)*100 exceeds (47000— S )/10,000 +1 for psi [(324— S )/69 +1 for MPa] when S is greater than 37,000 psi (255 MPa) but less than 47,000 psi (324 MPa), and where (h/D)*100 exceeds 1 when S is 47,000 psi (324 MPa) or more.
(ii) Where:
(A) D = Outside diameter of the pipe, in. (mm);
(B) h = Crest-to-trough height of the ripple, in. (mm); and
(C) S = Maximum operating hoop stress, psi (S/145, MPa).
§ 192.5   Class locations.
(a) This section classifies pipeline locations for purposes of this part. The following criteria apply to classifications under this section.
(1) A “class location unit” is an onshore area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1- mile (1.6 kilometers) length of pipeline.
(2) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy.
(b) Except as provided in paragraph (c) of this section, pipeline locations are classified as follows:
(1) A Class 1 location is:
(i) An offshore area; or
(ii) Any class location unit that has 10 or fewer buildings intended for human occupancy.
(2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy.
(3) A Class 3 location is:
(i) Any class location unit that has 46 or more buildings intended for human occupancy; or
(ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.)
(4) A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent.
(c) The length of Class locations 2, 3, and 4 may be adjusted as follows:
(1) A Class 4 location ends 220 yards (200 meters) from the nearest building with four or more stories above ground.
(2) When a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster.
(d) An operator must have records that document the current class location of each gas transmission pipeline segment and that demonstrate how the operator determined each current class location in accordance with this section.
§ 192.7   What documents are incorporated by reference partly or wholly in this part?
(a) Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. All approved incorporation by reference (IBR) material is available for inspection at the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the National Archives and Records Administration (NARA). Contact PHMSA at: Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590; 202-366-4046; www.phmsa.dot.gov/pipeline/regs. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations.html or email fr.inspection@nara.gov. It is also available from the sources in the following paragraphs of this section.
(b) American Petroleum Institute (API), 200 Massachusetts Avenue NW, Suite 1100, Washington, DC 20001-5571; phone: (202) 682-8000; website: www.api.org.
(1) API Recommended Practice 5L1, “Recommended Practice for Railroad Transportation of Line Pipe,” 7th edition, September 2009, (API RP 5L1), IBR approved for § 192.65(a).
(2) API Recommended Practice 5LT, “Recommended Practice for Truck Transportation of Line Pipe,” First edition, March 2012, (API RP 5LT), IBR approved for § 192.65(c).
(3) API Recommended Practice 5LW, “Recommended Practice for Transportation of Line Pipe on Barges and Marine Vessels,” 3rd edition, September 2009, (API RP 5LW), IBR approved for § 192.65(b).
(4) API Recommended Practice 80, “Guidelines for the Definition of Onshore Gas Gathering Lines,” 1st edition, April 2000, (API RP 80), IBR approved for § 192.8(a).
(5) API Recommended Practice 1162, “Public Awareness Programs for Pipeline Operators,” 1st edition, December 2003, (API RP 1162), IBR approved for § 192.616(a), (b), and (c).
(6) API Recommended Practice 1165, “Recommended Practice for Pipeline SCADA Displays,” First edition, January 2007, (API RP 1165), IBR approved for § 192.631(c).
(7) API Specification 5L, Line Pipe, 46th edition, April 2018, including Errata 1 (May 2018), (API Spec 5L); IBR approved for §§ 192.55(e); 192.112(a), (b), (c), (d), and (e); 192.113; appendix B to part 192.
(8) API Specification 6D, Specification for Pipeline and Piping Valves, 24th edition, August 2014, including Errata 1 through 10 (October 2014 through July 2021), Addendum 1 (March 2015), and Addendum 2 (June 2016), (API Spec 6D); IBR approved for § 192.145(a).
(9) API Standard 1104, Welding of Pipelines and Related Facilities, 21st edition, September 2013, including Errata 1 through 5 (April 2014 through September 2018), Addendum 1 (2014), and Addendum 2 (2016), (API Std 1104); IBR approved for §§ 192.225(a); 192.227(a); 192.229(b) and (c); 192.241(c); appendix B to part 192.
(10) API Recommended Practice 1170, “Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage,” First edition, July 2015 (API RP 1170), IBR approved for § 192.12.
(11) API Recommended Practice 1171, “Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs,” First edition, September 2015, (API RP 1171), IBR approved for § 192.12.
(12) API STANDARD 1163, “In-Line Inspection Systems Qualification,” Second edition, April 2013, Reaffirmed August 2018, (API STD 1163), IBR approved for § 192.493.
(c) American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016; phone: (800) 843-2763; email: CustomerCare@asme.org; website: www.asme.org/.
(1) ASME/ANSI B16.1-2005, “Gray Iron Pipe Flanges and Flanged Fittings: (Classes 25, 125, and 250),” August 31, 2006, (ASME/ANSI B16.1), IBR approved for § 192.147(c).
(2) ASME/ANSI B16.5-2003, Pipe Flanges and Flanged Fittings, October 2004, (ASME/ANSI B16.5); IBR approved for §§ 192.147(a); 192.607(f).
(3) ASME B16.40-2008, “Manually Operated Thermoplastic Gas Shutoffs and Valves in Gas Distribution Systems,” March 18, 2008, approved by ANSI, (ASME B16.40-2008), IBR approved for Item I, Appendix B to Part 192.
(4) ASME/ANSI B31G-1991 (Reaffirmed 2004), “Manual for Determining the Remaining Strength of Corroded Pipelines,” 2004, (ASME/ANSI B31G), IBR approved for §§ 192.485(c), 192.632(a), 192.712(b), and 192.933(a).
(5) ASME B31.8-2018, Gas Transmission and Distribution Piping Systems, Issued November 20, 2018, (ASME B31.8); IBR approved for §§ 192.112(b); 192.619(a).
(6) ASME/ANSI B31.8S-2004, “Supplement to B31.8 on Managing System Integrity of Gas Pipelines,” approved January 14, 2005, (ASME/ANSI B31.8S-2004), IBR approved for §§ 192.714(d); 192.933(d).
(7) ASME B31.8S-2018, Managing System Integrity of Gas Pipelines, Issued November 28, 2018, (ASME B31.8S); IBR approved for §§ 192.13(d); 192.714(c); 192.903 note to Potential impact radius; 192.907 introductory text and (b); 192.911 introductory text, (i), and (k) through (m); 192.913(a) through (c); 192.917(a) through (e); 192.921(a); 192.923(b); 192.925(b); 192.933(c); 192.935(b); 192.937(c); 192.939(a); 192.945(a).
(8) ASME B36.10M-2018, Welded and Seamless Wrought Steel Pipe, Issued October 12, 2018, (ASME B36.10M); IBR approved for § 192.279.
(9) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1 “Rules for Construction of Pressure Vessels,” 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 1), IBR approved for §§ 192.153(a), (b), (d); and 192.165(b).
(10) ASME Boiler & Pressure Vessel Code, Section VIII, Division 2 “Alternate Rules, Rules for Construction of Pressure Vessels,” 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 2), IBR approved for §§ 192.153(b), (d); and 192.165(b).
(11) ASME Boiler & Pressure Vessel Code, Section IX: “Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators,” 2007 edition, July 1, 2007, ASME BPVC, Section IX, IBR approved for §§ 192.225(a); 192.227(a); and Item II, Appendix B to Part 192.
(d) American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228, phone: 800-222-2768, website: https://www.asnt.org/.
(1) ANSI/ASNT ILI-PQ-2005(2010), “In-line Inspection Personnel Qualification and Certification,” Reapproved October 11, 2010, (ANSI/ASNT ILI-PQ), IBR approved for § 192.493.
(2) [Reserved]
(e) ASTM International (ASTM), 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428; phone: (610) 832-9585; email: service@astm.org; website: www.astm.org.
(1) ASTM A53/A53M-20, Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless, approved July 1, 2020, (ASTM A53/A53M); IBR approved for § 192.113; appendix B to part 192.
(2) ASTM A106/A106M-19A, Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service, approved November 1, 2019, (ASTM A106/A106M); IBR approved for § 192.113; appendix B to part 192.
(3) ASTM A333/A333M-18, Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service and Other Applications with Required Notch Toughness, approved November 1, 2018, (ASTM A333/A333M); IBR approved for § 192.113; appendix B to part 192.
(4) ASTM A372/A372M-10, “Standard Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure Vessels,” approved October 1, 2010, (ASTM A372/A372M), IBR approved for § 192.177(b).
(5) ASTM A381/A381M-18, Standard Specification for Metal-Arc-Welded Carbon or High-Strength Low-Alloy Steel Pipe for Use with High-Pressure Transmission Systems, approved November 1, 2018, (ASTM A381); IBR approved for § 192.113; appendix B to part 192.
(6) ASTM A578/A578M-96 (reapproved 2001), “Standard Specification for Straight-Beam Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications,” (ASTM A578/A578M), IBR approved for § 192.112(c).
(7) ASTM A671/A671M-20, Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures, approved March 1, 2020, (ASTM A671/A671M); IBR approved for § 192.113; appendix B to part 192.
(8) ASTM A672/A672M-09, “Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures,” approved October 1, 2009, (ASTM A672/672M), IBR approved for § 192.113 and Item I, Appendix B to Part 192.
(9) ASTM A691/A691M-19, Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures, approved November 1, 2019, (ASTM A691/A691M); IBR approved for § 192.113; appendix B to part 192.
(10) ASTM D638-03, “Standard Test Method for Tensile Properties of Plastics,” 2003, (ASTM D638), IBR approved for § 192.283(a) and (b).
(11) ASTM D2513-18a, “Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings,” approved August 1, 2018, (ASTM D2513), IBR approved for Item I, Appendix B to Part 192.
(12) ASTM D2517-00, “Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings,” (ASTM D 2517), IBR approved for §§ 192.191(a); 192.281(d); 192.283(a); and Item I, Appendix B to Part 192.
(13) ASTM D2564-12, “Standard Specification for Solvent Cements for Poly (Vinyl Chloride) (PVC) Plastic Piping Systems,” Aug. 1, 2012, (ASTM D2564-12), IBR approved for § 192.281(b)(2).
(14) ASTM F1055-98 (Reapproved 2006), “Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing,” March 1, 2006, (ASTM F1055-98 (2006)), IBR approved for § 192.283(a), Item I, Appendix B to Part 192.
(15) ASTM F1924-12, “Standard Specification for Plastic Mechanical Fittings for Use on Outside Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing,” April 1, 2012, (ASTM F1924-12), IBR approved for Item I, Appendix B to Part 192.
(16) ASTM F1948-12, “Standard Specification for Metallic Mechanical Fittings for Use on Outside Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing,” April 1, 2012, (ASTM F1948-12), IBR approved for Item I, Appendix B to Part 192.
(17) ASTM F1973-13, “Standard Specification for Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene (PE) and Polyamide 11 (PA11) and Polyamide 12 (PA12) Fuel Gas Distribution Systems,” May 1, 2013, (ASTM F1973-13), IBR approved for § 192.204(b); and Item I, Appendix B to Part 192.
(18) ASTM F2145-13, “Standard Specification for Polyamide 11 (PA 11) and Polyamide 12 (PA12) Mechanical Fittings for Use on Outside Diameter Controlled Polyamide 11 and Polyamide 12 Pipe and Tubing,” May 1, 2013, (ASTM F2145-13), IBR approved for Item I, Appendix B to Part 192.
(19) ASTM F 2600-09, “Standard Specification for Electrofusion Type Polyamide-11 Fittings for Outside Diameter Controlled Polyamide-11 Pipe and Tubing,” April 1, 2009, (ASTM F 2600-09), IBR approved for Item I, Appendix B to Part 192.
(20) ASTM F2620-19, “Standard Practice for Heat Fusion Joining of Polyethylene Pipe and Fittings,” approved February 1, 2019, (ASTM F2620), IBR approved for §§ 192.281(c) and 192.285(b).
(21) ASTM F2767-12, “Specification for Electrofusion Type Polyamide-12 Fittings for Outside Diameter Controlled Polyamide-12 Pipe and Tubing for Gas Distribution,” Oct. 15, 2012, (ASTM F2767-12), IBR approved for Item I, Appendix B to Part 192.
(22) ASTM F2785-12, “Standard Specification for Polyamide 12 Gas Pressure Pipe, Tubing, and Fittings,” Aug. 1, 2012, (ASTM F2785-12), IBR approved for Item I, Appendix B to Part 192.
(23) ASTM F2817-10, “Standard Specification for Poly (Vinyl Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or Repair,” Feb. 1, 2010, (ASTM F2817-10), IBR approved for Item I, Appendix B to Part 192.
(24) ASTM F2945-12a “Standard Specification for Polyamide 11 Gas Pressure Pipe, Tubing, and Fittings,” Nov. 27, 2012, (ASTM F2945-12a), IBR approved for Item I, Appendix B to Part 192.
(f) [Reserved]
(g) Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park St. NE, Vienna, VA 22180; phone: (703) 281-6613; email: info@msshq.org; website: www.mss-hq.org/.
(1) ANSI/MSS SP-44-2019, Steel Pipeline Flanges, published April 2020, (MSS SP-44); IBR approved for § 192.147(a).
(2) [Reserved]
(h) NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084: phone: 281-228-6223 or 800-797-6223, Web site: http://www.nace.org/Publications/.
(1) NACE Standard Practice 0102-2010, “In-Line Inspection of Pipelines,” Revised 2010-03-13, (NACE SP0102), IBR approved for §§ 192.150(a) and 192.493.
(2) NACE SP0204-2008, Standard Practice, “Stress Corrosion Cracking (SCC) Direct Assessment Methodology,” reaffirmed September 18, 2008, (NACE SP0204); IBR approved for §§ 192.923(b); 192.929(b) introductory text, (b)(1) through (3), (b)(5) introductory text, and (b)(5)(i).
(3) NACE SP0206-2006, Standard Practice, “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA),” approved December 1, 2006, (NACE SP0206), IBR approved for §§ 192.923(b); 192.927(b), (c) introductory text, and (c)(1) through (4).
(4) ANSI/NACE SP0502-2010, Standard Practice, “Pipeline External Corrosion Direct Assessment Methodology,” revised June 24, 2010, (NACE SP0502), IBR approved for §§ 192.319(f); 192.461(h); 192.923(b); 192.925(b); 192.931(d); 192.935(b); and 192.939(a).
(i) National Fire Protection Association (NFPA), 1 Batterymarch Park, Quincy, MA 02169; phone: (617) 984-7275; website: www.nfpa.org.
(1) NFPA-30 (2012), “Flammable and Combustible Liquids Code,” 2012 edition, June 20, 2011, including Errata 30-12-1 (September 27, 2011) and Errata 30-12-2 (November 14, 2011), (NFPA-30), IBR approved for § 192.735(b).
(2) NFPA 58, Liquefied Petroleum Gas Code, 2020 edition, effective August 25, 2019, (NFPA 58); IBR approved for § 192.11.
(3) NFPA 59, Utility LP-Gas Plant Code, 2018 edition, effective September 6, 2017, (NFPA 59); IBR approved for § 192.11.
(4) NFPA 70, National Electrical Code (NEC), 2017 edition, effective August 24, 2016, (NFPA 70); IBR approved for §§ 192.163(e); 192.189(c).
(j) Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, P.O. Box 980550, Houston, TX 77098, phone: 713-630-0505, toll free: 866-866-6766, Web site: http://www.ttoolboxes.com/. (Contract number PR-3-805.)
(1) AGA, Pipeline Research Committee Project, PR-3-805, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,” (December 22, 1989), (PRCI PR-3-805 (R-STRENG)), IBR approved for §§ 192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d).
(2) [Reserved]
(k) Plastics Pipe Institute, Inc. (PPI), 105 Decker Court, Suite 825 Irving TX 75062, phone: 469-499-1044, http://www.plasticpipe.org/.
(1) PPI TR-3/2012, HDB/HDS/PDB/SDB/MRS/CRS, Policies, “Policies and Procedures for Developing Hydrostatic Design Basis (HDB), Hydrostatic Design Stresses (HDS), Pressure Design Basis (PDB), Strength Design Basis (SDB), Minimum Required Strength (MRS) Ratings, and Categorized Required Strength (CRS) for Thermoplastic Piping Materials or Pipe,” updated November 2012, (PPI TR-3/2012), IBR approved for § 192.121.
(2) PPI TR-4, HDB/HDS/SDB/MRS, Listed Materials, “PPI Listing of Hydrostatic Design Basis (HDB), Hydrostatic Design Stress (HDS), Strength Design Basis (SDB), Pressure Design Basis (PDB) and Minimum Required Strength (MRS) Rating For Thermoplastic Piping Materials or Pipe,” updated March, 2011, (PPI TR-4/2012), IBR approved for § 192.121.
§ 192.8   How are onshore gathering pipelines and regulated onshore gathering pipelines determined?
(a) An operator must use API RP 80 (incorporated by reference, see § 192.7), to determine if an onshore pipeline (or part of a connected series of pipelines) is an onshore gathering line. The determination is subject to the limitations listed below. After making this determination, an operator must determine if the onshore gathering line is a regulated onshore gathering line under paragraph (b) of this section.
(1) The beginning of gathering, under section 2.2(a)(1) of API RP 80, may not extend beyond the furthermost downstream point in a production operation as defined in section 2.3 of API RP 80. This furthermost downstream point does not include equipment that can be used in either production or transportation, such as separators or dehydrators, unless that equipment is involved in the processes of “production and preparation for transportation or delivery of hydrocarbon gas” within the meaning of “production operation.”
(2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 80, may not extend beyond the first downstream natural gas processing plant, unless the operator can demonstrate, using sound engineering principles, that gathering extends to a further downstream plant.
(3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API RP 80, is determined by the commingling of gas from separate production fields, the fields may not be more than 50 miles from each other, unless the Administrator finds a longer separation distance is justified in a particular case (see 49 CFR § 190.9).
(4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 80, may not extend beyond the furthermost downstream compressor used to increase gathering line pressure for delivery to another pipeline.
(5) For new, replaced, relocated, or otherwise changed gas gathering pipelines installed after May 16, 2022, the endpoint of gathering under sections 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 (incorporated by reference, see § 192.7)—also known as “incidental gathering”—may not be used if the pipeline terminates 10 or more miles downstream from the furthermost downstream endpoint as defined in paragraphs 2.2(a)(1)(A) through (a)(1)(D) of API RP 80 (incorporated by reference, see § 192.7) and this section. If an “incidental gathering” pipeline is 10 miles or more in length, the entire portion of the pipeline that is designated as an incidental gathering line under 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 shall be classified as a transmission pipeline subject to all applicable regulations in this chapter for transmission pipelines.
(b) Each operator must determine and maintain for the life of the pipeline records documenting the methodology by which it calculated the beginning and end points of each onshore gathering pipeline it operates, as described in the second column of table 1 to paragraph (c)(2) of this section, by:
(1) November 16, 2022, or before the pipeline is placed into operation, whichever is later; or
(2) An alternative deadline approved by the Pipeline and Hazardous Materials Safety Administration (PHMSA). The operator must notify PHMSA and State or local pipeline safety authorities, as applicable, no later than 90 days in advance of the deadline in paragraph (b)(1) of this section. The notification must be made in accordance with § 192.18 and must include the following information:
(i) Description of the affected facilities and operating environment;
(ii) Justification for an alternative compliance deadline; and
(iii) Proposed alternative deadline.
(c) For purposes of part 191 of this chapter and § 192.9, the term “regulated onshore gathering pipeline” means:
(1) Each Type A, Type B, or Type C onshore gathering pipeline (or segment of onshore gathering pipeline) with a feature described in the second column of table 1 to paragraph (c)(2) of this section that lies in an area described in the third column; and
(2) As applicable, additional lengths of pipeline described in the fourth column to provide a safety buffer:
Table 1 to Paragraph ( c )(2)
(3) A Type R gathering line is subject to reporting requirements under part 191 of this chapter but is not a regulated onshore gathering line under this part.
(4) For the purpose of identifying Type C lines in table 1 to paragraph (c)(2) of this section, if an operator has not calculated MAOP consistent with the methods at § 192.619(a) or (c)(1), the operator must either:
(i) Calculate MAOP consistent with the methods at § 192.619(a) or (c)(1); or
(ii) Use as a substitute for MAOP the highest operating pressure to which the segment was subjected during the preceding 5 operating years.
§ 192.9   What requirements apply to gathering pipelines?
(a) Requirements. An operator of a gathering line must follow the safety requirements of this part as prescribed by this section.
(b) Offshore lines. An operator of an offshore gathering line must comply with requirements of this part applicable to transmission lines, except the requirements in §§ 192.13(d), 192.150, 192.285(e), 192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.485(c), 192.493, 192.506, 192.607, 192.613(c), 192.619(e), 192.624, 192.710, 192.712, and 192.714, and in subpart O of this part. Further, operators of offshore gathering lines are exempt from the requirements of §§ 192.617(b) through (d) and 192.635. Lastly, operators of offshore gathering lines are exempt from the requirements of § 192.615 (but an operator of an offshore gathering line must comply with the requirements of 49 CFR 192.615, effective as of October 4, 2022).
(c) Type A lines. An operator of a Type A regulated onshore gathering line must comply with the requirements of this part applicable to transmission lines, except the requirements in §§ 192.13(d), 192.150, 192.285(e), 192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.485(c) 192.493, 192.506, 192.607, 192.613(c), 192.619(e), 192.624, 192.710, 192.712, and 192.714, and in subpart O of this part. However, an operator of a Type A regulated onshore gathering line in a Class 2 location may demonstrate compliance with subpart N of this part by describing the processes it uses to determine the qualification of persons performing operations and maintenance tasks. Further, operators of Type A regulated onshore gathering lines are exempt from the requirements of §§ 192.179(e) through (g), 192.610, 192.617(b) through (d), 192.634, 192.635, 192.636, and 192.745(c) through (f). Lastly, operators of Type A regulated onshore gathering lines are exempt from the requirements of § 192.615 (but an operator of a Type A regulated onshore gathering line must comply with the requirements of 49 CFR 192.615, effective as of October 4, 2022).
(d) Type B lines. An operator of a Type B regulated onshore gathering line must comply with the following requirements:
(1) If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial testing must be in accordance with requirements of this part applicable to transmission lines. Compliance with §§ 192.67, 192.127, 192.179(e) and (f), 192.205, 192.227(c), 192.285(e), 192.319(d) through (g), 192.506, 192.634, and 192.636 is not required;
(2) If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines, except the requirements in §§ 192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.485(c), and 192.493;
(3) If the pipeline contains plastic pipe or components, the operator must comply with all applicable requirements of this part for plastic pipe components;
(4) Carry out a damage prevention program under § 192.614;
(5) Establish a public education program under § 192.616;
(6) Establish the MAOP of the line under § 192.619(a), (b), and (c);
(7) Install and maintain line markers according to the requirements for transmission lines in § 192.707; and
(8) Conduct leakage surveys in accordance with the requirements for transmission lines in § 192.706, using leak-detection equipment, and promptly repair hazardous leaks in accordance with § 192.703(c).
(e) Type C lines. The requirements for Type C gathering lines are as follows.
(1) An operator of a Type C onshore gathering line with an outside diameter greater than or equal to 8.625 inches must comply with the following requirements:
(i) Except as provided in paragraph (h) of this section for pipe and components made with composite materials, the design, installation, construction, initial inspection, and initial testing of a new, replaced, relocated, or otherwise changed Type C gathering line, must be done in accordance with the requirements in subparts B through G and J of this part applicable to transmission lines. Compliance with §§ 192.67, 192.127, 192.179(e) and (f), 192.205, 192.227(c), 192.285(e), 192.319(d) through (g), 192.506, 192.634, and 192.636 is not required;
(ii) If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines, except the requirements in §§ 192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.485(c), and 192.493;
(iii) Carry out a damage prevention program under § 192.614;
(iv) Develop and implement procedures for emergency plans in accordance with the requirements of 49 CFR 192.615, effective as of October 4, 2022;
(v) Develop and implement a written public awareness program in accordance with § 192.616;
(vi) Install and maintain line markers according to the requirements for transmission lines in § 192.707; and
(vii) Conduct leakage surveys in accordance with the requirements for transmission lines in § 192.706 using leak-detection equipment, and promptly repair hazardous leaks in accordance with § 192.703(c).
(2) An operator of a Type C onshore gathering line with an outside diameter greater than 12.75 inches must comply with the requirements in paragraph (e)(1) of this section and the following:
(i) If the pipeline contains plastic pipe, the operator must comply with all applicable requirements of this part for plastic pipe or components. This does not include pipe and components made of composite materials that incorporate plastic in the design; and
(ii) Establish the MAOP of the pipeline under § 192.619(a) or (c) and maintain records used to establish the MAOP for the life of the pipeline.
(f) Exceptions. (1) Compliance with paragraphs (e)(1)(ii), (v), (vi), and (vii) and (e)(2)(i) and (ii) of this section is not required for pipeline segments that are 16 inches or less in outside diameter if one of the following criteria are met:
(i) Method 1. The segment is not located within a potential impact circle containing a building intended for human occupancy or other impacted site. The potential impact circle must be calculated as specified in § 192.903, except that a factor of 0.73 must be used instead of 0.69. The MAOP used in this calculation must be determined and documented in accordance with paragraph (e)(2)(ii) of this section.
(ii) Method 2. The segment is not located within a class location unit ( see § 192.5) containing a building intended for human occupancy or other impacted site.
(2) Paragraph (e)(1)(i) of this section is not applicable to pipeline segments 40 feet or shorter in length that are replaced, relocated, or changed on a pipeline existing on or before May 16, 2022.
(3) For purposes of this section, the term “building intended for human occupancy or other impacted site” means any of the following:
(i) Any building that may be occupied by humans, including homes, office buildings factories, outside recreation areas, plant facilities, etc.;
(ii) A small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period (the days and weeks need not be consecutive); or
(iii) Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes.
(g) Compliance deadlines. An operator of a regulated onshore gathering line must comply with the following deadlines, as applicable.
(1) An operator of a new, replaced, relocated, or otherwise changed line must be in compliance with the applicable requirements of this section by the date the line goes into service, unless an exception in § 192.13 applies.
(2) If a Type A or Type B regulated onshore gathering pipeline existing on April 14, 2006, was not previously subject to this part, an operator has until the date stated in the second column to comply with the applicable requirement for the pipeline listed in the first column, unless the Administrator finds a later deadline is justified in a particular case:
(3) If, after April 14, 2006, a change in class location or increase in dwelling density causes an onshore gathering pipeline to become a Type A or Type B regulated onshore gathering line, the operator has 1 year for Type B lines and 2 years for Type A lines after the pipeline becomes a regulated onshore gathering pipeline to comply with this section.
(4) If a Type C gathering pipeline existing on or before May 16, 2022, was not previously subject to this part, an operator must comply with the applicable requirements of this section, except for paragraph (h) of this section, on or before:
(i) May 16, 2023; or
(ii) An alternative deadline approved by PHMSA. The operator must notify PHMSA and State or local pipeline safety authorities, as applicable, no later than 90 days in advance of the deadline in paragraph (b)(1) of this section. The notification must be made in accordance with § 192.18 and must include a description of the affected facilities and operating environment, the proposed alternative deadline for each affected requirement, the justification for each alternative compliance deadline, and actions the operator will take to ensure the safety of affected facilities.
(5) If, after May 16, 2022, a change in class location, an increase in dwelling density, or an increase in MAOP causes a pipeline to become a Type C gathering pipeline, or causes a Type C gathering pipeline to become subject to additional Type C requirements ( see paragraph (f) of this section), the operator has 1 year after the pipeline becomes subject to the additional requirements to comply with this section.
(h) Composite materials. Pipe and components made with composite materials not otherwise authorized for use under this part may be used on Type C gathering pipelines if the following requirements are met:
(1) Steel and plastic pipe and components must meet the installation, construction, initial inspection, and initial testing requirements in subparts B though G and J of this part applicable to transmission lines.
(2) Operators must notify PHMSA in accordance with § 192.18 at least 90 days prior to installing new or replacement pipe or components made of composite materials otherwise not authorized for use under this part in a Type C gathering pipeline. The notifications required by this section must include a detailed description of the pipeline facilities in which pipe or components made of composite materials would be used, including:
(i) The beginning and end points (stationing by footage and mileage with latitude and longitude coordinates) of the pipeline segment containing composite pipeline material and the counties and States in which it is located;
(ii) A general description of the right-of-way including high consequence areas, as defined in § 192.905;
(iii) Relevant pipeline design and construction information including the year of installation, the specific composite material, diameter, wall thickness, and any manufacturing and construction specifications for the pipeline;
(iv) Relevant operating information, including MAOP, leak and failure history, and the most recent pressure test (identification of the actual pipe tested, minimum and maximum test pressure, duration of test, any leaks and any test logs and charts) or assessment results;
(v) An explanation of the circumstances that the operator believes make the use of composite pipeline material appropriate and how the design, construction, operations, and maintenance will mitigate safety and environmental risks;
(vi) An explanation of procedures and tests that will be conducted periodically over the life of the composite pipeline material to document that its strength is being maintained;
(vii) Operations and maintenance procedures that will be applied to the alternative materials. These include procedures that will be used to evaluate and remediate anomalies and how the operator will determine safe operating pressures for composite pipe when defects are found;
(viii) An explanation of how the use of composite pipeline material would be in the public interest; and
(ix) A certification signed by a vice president (or equivalent or higher officer) of the operator's company that operation of the applicant's pipeline using composite pipeline material would be consistent with pipeline safety.
(3) Repairs or replacements using materials authorized under this part do not require notification under this section.
§ 192.10   Outer continental shelf pipelines.
Operators of transportation pipelines on the Outer Continental Shelf (as defined in the Outer Continental Shelf Lands Act; 43 U.S.C. 1331) must identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 1998 to identify the transfer points. If it is not practicable to durably mark a transfer point and the transfer point is located above water, the operator must depict the transfer point on a schematic located near the transfer point. If a transfer point is located subsea, then the operator must identify the transfer point on a schematic which must be maintained at the nearest upstream facility and provided to PHMSA upon request. For those cases in which adjoining operators have not agreed on a transfer point by September 15, 1998 the Regional Director and the MMS Regional Supervisor will make a joint determination of the transfer point.
§ 192.11   Petroleum gas systems.
(a) Each plant that supplies petroleum gas by pipeline to a natural gas distribution system must meet the requirements of this part and NFPA 58 or NFPA 59 (both incorporated by reference, see § 192.7), based on the scope and applicability statements in those standards.
(b) Each pipeline system subject to this part that transports only petroleum gas or petroleum gas/air mixtures must meet the requirements of this part and NFPA 58 or NFPA 59 (both incorporated by reference, see § 192.7), based on the scope and applicability statements in those standards.
(c) In the event of a conflict between this part and NFPA 58 or NFPA 59 (both incorporated by reference, see § 192.7), NFPA 58 or NFPA 59 shall prevail if applicable based on the scope and applicability statements in those standards.
§ 192.12   Underground natural gas storage facilities.
Underground natural gas storage facilities (UNGSFs), as defined in § 192.3, are not subject to any requirements of this part aside from this section.
(a) Salt cavern UNGSFs. (1) Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed after March 13, 2020, must meet all the provisions of API RP 1170 (incorporated by reference, see § 192.7), the provisions of section 8 of API RP 1171 (incorporated by reference, see § 192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraphs (c) and (d) of this section prior to commencing operations.
(2) Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed between July 18, 2017, and March 13, 2020, must meet all the provisions of API RP 1170 (incorporated by reference, see § 192.7) and paragraph (c) of this section prior to commencing operations, and must meet all the provisions of section 8 of API RP 1171 (incorporated by reference, see § 192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraph (d) of this section, by March 13, 2021.
(3) Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed on or before July 18, 2017, must meet the provisions of API RP 1170 (incorporated by reference, see § 192.7), sections 9, 10, and 11, and paragraph (c) of this section, by January 18, 2018, and must meet all provisions of section 8 of API RP 1171 (incorporated by reference, see § 192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraph (d) of this section, by March 13, 2021.
(b) Depleted hydrocarbon and aquifer reservoir UNGSFs. (1) Each UNGSF that uses a depleted hydrocarbon reservoir or an aquifer reservoir for natural gas storage and was constructed after July 18, 2017, must meet all provisions of API RP 1171 (incorporated by reference, see § 192.7), and paragraphs (c) and (d) of this section, prior to commencing operations.
(2) Each UNGSF that uses a depleted hydrocarbon reservoir or an aquifer reservoir for natural gas storage and was constructed on or before July 18, 2017, must meet the provisions of API RP 1171 (incorporated by reference, see § 192.7), sections 8, 9, 10, and 11, and paragraph (c) of this section, by January 18, 2018, and must meet all provisions of paragraph (d) of this section by March 13, 2021.
(c) Procedural manuals. Each operator of a UNGSF must prepare and follow for each facility one or more manuals of written procedures for conducting operations, maintenance, and emergency preparedness and response activities under paragraphs (a) and (b) of this section. Each operator must keep records necessary to administer such procedures and review and update these manuals at intervals not exceeding 15 months, but at least once each calendar year. Each operator must keep the appropriate parts of these manuals accessible at locations where UNGSF work is being performed. Each operator must have written procedures in place before commencing operations or beginning an activity not yet implemented.
(d) Integrity management program —(1) Integrity management program elements. The integrity management program for each UNGSF under this paragraph (d) must consist, at a minimum, of a framework developed under API RP 1171 (incorporated by reference, see § 192.7), section 8 (“Risk Management for Gas Storage Operations”), and that also describes how relevant decisions will be made and by whom. An operator must make continual improvements to the program and its execution. The integrity management program must include the following elements:
(i) A plan for developing and implementing each program element to meet the requirements of this section;
(ii) An outline of the procedures to be developed;
(iii) The roles and responsibilities of UNGSF staff assigned to develop and implement the procedures required by this paragraph (d);
(iv) A plan for how staff will be trained in awareness and application of the procedures required by this paragraph (d);
(v) Timelines for implementing each program element, including the risk analysis and baseline risk assessments; and
(vi) A plan for how to incorporate information gained from experience into the integrity management program on a continuous basis.
(2) Integrity management baseline risk-assessment intervals. No later than March 13, 2024, each UNGSF operator must complete the baseline risk assessments of all reservoirs and caverns, and at least 40% of the baseline risk assessments for each of its UNGSF wells (including wellhead assemblies), beginning with the highest-risk wells, as identified by the risk analysis process. No later than March 13, 2027, an operator must complete baseline risk assessments on all its wells (including wellhead assemblies). Operators may use prior risk assessments for a well as a baseline (or part of the baseline) risk assessment in implementing its initial integrity management program, so long as the prior assessments meet the requirements of API RP 1171 (incorporated by reference, see § 192.7), section 8, and continue to be relevant and valid for the current operating and environmental conditions. When evaluating prior risk-assessment results, operators must account for the growth and effects of indicated defects since the time the assessment was performed.
(3) Integrity management re-assessment intervals. The operator must determine the appropriate interval for risk assessments under API RP 1171 (incorporated by reference, see § 192.7), subsection 8.7.1, and this paragraph (d) for each reservoir, cavern, and well, using the results from earlier assessments and updated risk analyses. The re-assessment interval for each reservoir, cavern, and well must not exceed seven years from the date of the baseline assessment for each reservoir, cavern, and well.
(4) Integrity management procedures and recordkeeping. Each UNGSF operator must establish and follow written procedures to carry out its integrity management program under API RP 1171 (incorporated by reference, see § 192.7), section 8 (“Risk Management for Gas Storage Operations”), and this paragraph (d). The operator must also maintain, for the useful life of the UNGSF, records that demonstrate compliance with the requirements of this paragraph (d). This includes records developed and used in support of any identification, calculation, amendment, modification, justification, deviation, and determination made, and any action taken to implement and evaluate any integrity management program element.
§ 192.13   What general requirements apply to pipelines regulated under this part?
(a) No person may operate a segment of pipeline listed in the first column of paragraph (a)(3) of this section that is readied for service after the date in the second column, unless:
(1) The pipeline has been designed, installed, constructed, initially inspected, and initially tested in accordance with this part; or
(2) The pipeline qualifies for use under this part according to the requirements in § 192.14.
(3) The compliance deadlines are as follows:
(b) No person may operate a segment of pipeline listed in the first column of this paragraph (b) that is replaced, relocated, or otherwise changed after the date in the second column of this paragraph (b), unless the replacement, relocation or change has been made according to the requirements in this part.
(c) Each operator shall maintain, modify as appropriate, and follow the plans, procedures, and programs that it is required to establish under this part.
(d) Each operator of an onshore gas transmission pipeline must evaluate and mitigate, as necessary, significant changes that pose a risk to safety or the environment through a management of change process. Each operator of an onshore gas transmission pipeline must develop and follow a management of change process, as outlined in ASME B31.8S, section 11 (incorporated by reference, see § 192.7), that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, whether permanent or temporary. A management of change process must include the following: reason for change, authority for approving changes, analysis of implications, acquisition of required work permits, documentation, communication of change to affected parties, time limitations, and qualification of staff. For pipeline segments other than those covered in subpart O of this part, this management of change process must be implemented by February 26, 2024. The requirements of this paragraph (d) do not apply to gas gathering pipelines. Operators may request an extension of up to 1 year by submitting a notification to PHMSA at least 90 days before February 26, 2024, in accordance with § 192.18. The notification must include a reasonable and technically justified basis, an up-to-date plan for completing all actions required by this section, the reason for the requested extension, current safety or mitigation status of the pipeline segment, the proposed completion date, and any needed temporary safety measures to mitigate the impact on safety.
§ 192.14   Conversion to service subject to this part.
(a) A steel pipeline previously used in service not subject to this part qualifies for use under this part if the operator prepares and follows a written procedure to carry out the following requirements:
(1) The design, construction, operation, and maintenance history of the pipeline must be reviewed and, where sufficient historical records are not available, appropriate tests must be performed to determine if the pipeline is in a satisfactory condition for safe operation.
(2) The pipeline right-of-way, all aboveground segments of the pipeline, and appropriately selected underground segments must be visually inspected for physical defects and operating conditions which reasonably could be expected to impair the strength or tightness of the pipeline.
(3) All known unsafe defects and conditions must be corrected in accordance with this part.
(4) The pipeline must be tested in accordance with subpart J of this part to substantiate the maximum allowable operating pressure permitted by subpart L of this part.
(b) Each operator must keep for the life of the pipeline a record of the investigations, tests, repairs, replacements, and alterations made under the requirements of paragraph (a) of this section.
(c) An operator converting a pipeline from service not previously covered by this part must notify PHMSA 60 days before the conversion occurs as required by § 191.22 of this chapter.
§ 192.15   Rules of regulatory construction.
(a) As used in this part:
Includes means including but not limited to.
May means “is permitted to” or “is authorized to”.
May not means “is not permitted to” or “is not authorized to”.
Shall is used in the mandatory and imperative sense.
(b) In this part:
(1) Words importing the singular include the plural;
(2) Words importing the plural include the singular; and
(3) Words importing the masculine gender include the feminine.
§ 192.16   Customer notification.
(a) This section applies to each operator of a service line who does not maintain the customer's buried piping up to entry of the first building downstream, or, if the customer's buried piping does not enter a building, up to the principal gas utilization equipment or the first fence (or wall) that surrounds that equipment. For the purpose of this section, “customer's buried piping” does not include branch lines that serve yard lanterns, pool heaters, or other types of secondary equipment. Also, “maintain” means monitor for corrosion according to § 192.465 if the customer's buried piping is metallic, survey for leaks according to § 192.723, and if an unsafe condition is found, shut off the flow of gas, advise the customer of the need to repair the unsafe condition, or repair the unsafe condition.
(b) Each operator shall notify each customer once in writing of the following information:
(1) The operator does not maintain the customer's buried piping.
(2) If the customer's buried piping is not maintained, it may be subject to the potential hazards of corrosion and leakage.
(3) Buried gas piping should be—
(i) Periodically inspected for leaks;
(ii) Periodically inspected for corrosion if the piping is metallic; and
(iii) Repaired if any unsafe condition is discovered.
(4) When excavating near buried gas piping, the piping should be located in advance, and the excavation done by hand.
(5) The operator (if applicable), plumbing contractors, and heating contractors can assist in locating, inspecting, and repairing the customer's buried piping.
(c) Each operator shall notify each customer not later than August 14, 1996, or 90 days after the customer first receives gas at a particular location, whichever is later. However, operators of master meter systems may continuously post a general notice in a prominent location frequented by customers.
(d) Each operator must make the following records available for inspection by the Administrator or a State agency participating under 49 U.S.C. 60105 or 60106:
(1) A copy of the notice currently in use; and
(2) Evidence that notices have been sent to customers within the previous 3 years.
§ 192.18   How to notify PHMSA.
(a) An operator must provide any notification required by this part by—
(1) Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or
(2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE, Washington, DC 20590.
(b) An operator must also notify the appropriate State or local pipeline safety authority when an applicable pipeline segment is located in a State where OPS has an interstate agent agreement, or an intrastate applicable pipeline segment is regulated by that State.
(c) Unless otherwise specified, if an operator submits, pursuant to § 192.8, § 192.9, § 192.13, § 192.179, § 192.319, § 192.461, § 192.506, § 192.607, § 192.619, § 192.624, § 192.632, § 192.634, § 192.636, § 192.710, § 192.712, § 192.714, § 192.745, § 192.917, § 192.921, § 192.927, § 192.933, or § 192.937, a notification for use of a different integrity assessment method, analytical method, compliance period, sampling approach, pipeline material, or technique ( e.g., “other technology” or “alternative equivalent technology”) than otherwise prescribed in those sections, that notification must be submitted to PHMSA for review at least 90 days in advance of using the other method, approach, compliance timeline, or technique. An operator may proceed to use the other method, approach, compliance timeline, or technique 91 days after submitting the notification unless it receives a letter from the Associate Administrator for Pipeline Safety informing the operator that PHMSA objects to the proposal or that PHMSA requires additional time and/or more information to conduct its review.
§ 192.51   Scope.
This subpart prescribes minimum requirements for the selection and qualification of pipe and components for use in pipelines.
§ 192.53   General.
Materials for pipe and components must be:
(a) Able to maintain the structural integrity of the pipeline under temperature and other environmental conditions that may be anticipated;
(b) Chemically compatible with any gas that they transport and with any other material in the pipeline with which they are in contact; and
(c) Qualified in accordance with the applicable requirements of this subpart.
§ 192.55   Steel pipe.
(a) New steel pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification;
(2) It meets the requirements of—
(i) Section II of appendix B to this part; or
(ii) If it was manufactured before November 12, 1970, either section II or III of appendix B to this part; or
(3) It is used in accordance with paragraph (c) or (d) of this section.
(b) Used steel pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification and it meets the requirements of paragraph II-C of appendix B to this part;
(2) It meets the requirements of:
(i) Section II of appendix B to this part; or
(ii) If it was manufactured before November 12, 1970, either section II or III of appendix B to this part;
(3) It has been used in an existing line of the same or higher pressure and meets the requirements of paragraph II-C of appendix B to this part; or
(4) It is used in accordance with paragraph (c) of this section.
(c) New or used steel pipe may be used at a pressure resulting in a hoop stress of less than 6,000 p.s.i. (41 MPa) where no close coiling or close bending is to be done, if visual examination indicates that the pipe is in good condition and that it is free of split seams and other defects that would cause leakage. If it is to be welded, steel pipe that has not been manufactured to a listed specification must also pass the weldability tests prescribed in paragraph II-B of appendix B to this part.
(d) Steel pipe that has not been previously used may be used as replacement pipe in a segment of pipeline if it has been manufactured prior to November 12, 1970, in accordance with the same specification as the pipe used in constructing that segment of pipeline.
(e) New steel pipe that has been cold expanded must comply with the mandatory provisions of API Spec 5L (incorporated by reference, see § 192.7).
§ 192.57   [Reserved]
§ 192.59   Plastic pipe.
(a) New plastic pipe is qualified for use under this part if:
(1) It is manufactured in accordance with a listed specification;
(2) It is resistant to chemicals with which contact may be anticipated; and
(3) It is free of visible defects.
(b) Used plastic pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification;
(2) It is resistant to chemicals with which contact may be anticipated;
(3) It has been used only in gas service;
(4) Its dimensions are still within the tolerances of the specification to which it was manufactured; and
(5) It is free of visible defects.
(c) For the purpose of paragraphs (a)(1) and (b)(1) of this section, where pipe of a diameter included in a listed specification is impractical to use, pipe of a diameter between the sizes included in a listed specification may be used if it:
(1) Meets the strength and design criteria required of pipe included in that listed specification; and
(2) Is manufactured from plastic compounds which meet the criteria for material required of pipe included in that listed specification.
(d) Rework and/or regrind material is not allowed in plastic pipe produced after March 6, 2015 used under this part.
§ 192.61   [Reserved]
§ 192.63   Marking of materials.
(a) Except as provided in paragraph (d) and (e) of this section, each valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which it was manufactured.
(b) Surfaces of pipe and components that are subject to stress from internal pressure may not be field die stamped.
(c) If any item is marked by die stamping, the die must have blunt or rounded edges that will minimize stress concentrations.
(d) Paragraph (a) of this section does not apply to items manufactured before November 12, 1970, that meet all of the following:
(1) The item is identifiable as to type, manufacturer, and model.
(2) Specifications or standards giving pressure, temperature, and other appropriate criteria for the use of items are readily available.
(e) All plastic pipe and components must also meet the following requirements:
(1) All markings on plastic pipe prescribed in the listed specification and the requirements of paragraph (e)(2) of this section must be repeated at intervals not exceeding two feet.
(2) Plastic pipe and components manufactured after December 31, 2019 must be marked in accordance with the listed specification.
(3) All physical markings on plastic pipelines prescribed in the listed specification and paragraph (e)(2) of this section must be legible until the time of installation.
§ 192.65   Transportation of pipe.
(a) Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not install pipe having an outer diameter to wall thickness of 70 to 1, or more, that is transported by railroad unless the transportation is performed by API RP 5L1 (incorporated by reference, see § 192.7).
(b) Ship or barge. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by ship or barge on both inland and marine waterways unless the transportation is performed in accordance with API RP 5LW (incorporated by reference, see § 192.7).
(c) Truck. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by truck unless the transportation is performed in accordance with API RP 5LT (incorporated by reference, see § 192.7).
§ 192.67   Records: Material properties.
(a) For steel transmission pipelines installed after [July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records that document the physical characteristics of the pipeline, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition of materials for pipe in accordance with §§ 192.53 and 192.55. Records must include tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed.
(b) For steel transmission pipelines installed on or before July 1, 2020], if operators have records that document tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition in accordance with §§ 192.53 and 192.55, operators must retain such records for the life of the pipeline.
(c) For steel transmission pipeline segments installed on or before July 1, 2020], if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section.
§ 192.69   Storage and handling of plastic pipe and associated components.
Each operator must have and follow written procedures for the storage and handling of plastic pipe and associated components that meet the applicable listed specifications.
§ 192.101   Scope.
This subpart prescribes the minimum requirements for the design of pipe.
§ 192.103   General.
Pipe must be designed with sufficient wall thickness, or must be installed with adequate protection, to withstand anticipated external pressures and loads that will be imposed on the pipe after installation.
§ 192.105   Design formula for steel pipe.
(a) The design pressure for steel pipe is determined in accordance with the following formula:
(b) If steel pipe that has been subjected to cold expansion to meet the SMYS is subsequently heated, other than by welding or stress relieving as a part of welding, the design pressure is limited to 75 percent of the pressure determined under paragraph (a) of this section if the temperature of the pipe exceeds 900 °F (482 °C) at any time or is held above 600 °F (316 °C) for more than 1 hour.
§ 192.107   Yield strength (S) for steel pipe.
(a) For pipe that is manufactured in accordance with a specification listed in section I of appendix B of this part, the yield strength to be used in the design formula in § 192.105 is the SMYS stated in the listed specification, if that value is known.
(b) For pipe that is manufactured in accordance with a specification not listed in section I of appendix B to this part or whose specification or tensile properties are unknown, the yield strength to be used in the design formula in § 192.105 is one of the following:
(1) If the pipe is tensile tested in accordance with section II-D of appendix B to this part, the lower of the following:
(i) 80 percent of the average yield strength determined by the tensile tests.
(ii) The lowest yield strength determined by the tensile tests.
(2) If the pipe is not tensile tested as provided in paragraph (b)(1) of this section, 24,000 p.s.i. (165 MPa).
§ 192.109   Nominal wall thickness (t) for steel pipe.
(a) If the nominal wall thickness for steel pipe is not known, it is determined by measuring the thickness of each piece of pipe at quarter points on one end.
(b) However, if the pipe is of uniform grade, size, and thickness and there are more than 10 lengths, only 10 percent of the individual lengths, but not less than 10 lengths, need be measured. The thickness of the lengths that are not measured must be verified by applying a gauge set to the minimum thickness found by the measurement. The nominal wall thickness to be used in the design formula in § 192.105 is the next wall thickness found in commercial specifications that is below the average of all the measurements taken. However, the nominal wall thickness used may not be more than 1.14 times the smallest measurement taken on pipe less than 20 inches (508 millimeters) in outside diameter, nor more than 1.11 times the smallest measurement taken on pipe 20 inches (508 millimeters) or more in outside diameter.
§ 192.111   Design factor (F) for steel pipe.
(a) Except as otherwise provided in paragraphs (b), (c), and (d) of this section, the design factor to be used in the design formula in § 192.105 is determined in accordance with the following table:
(b) A design factor of 0.60 or less must be used in the design formula in § 192.105 for steel pipe in Class 1 locations that:
(1) Crosses the right-of-way of an unimproved public road, without a casing;
(2) Crosses without a casing, or makes a parallel encroachment on, the right-of-way of either a hard surfaced road, a highway, a public street, or a railroad;
(3) Is supported by a vehicular, pedestrian, railroad, or pipeline bridge; or
(4) Is used in a fabricated assembly, (including separators, mainline valve assemblies, cross-connections, and river crossing headers) or is used within five pipe diameters in any direction from the last fitting of a fabricated assembly, other than a transition piece or an elbow used in place of a pipe bend which is not associated with a fabricated assembly.
(c) For Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in § 192.105 for uncased steel pipe that crosses the right-of-way of a hard surfaced road, a highway, a public street, or a railroad.
(d) For Class 1 and Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in § 192.105 for—
(1) Steel pipe in a compressor station, regulating station, or measuring station; and
(2) Steel pipe, including a pipe riser, on a platform located offshore or in inland navigable waters.
§ 192.112   Additional design requirements for steel pipe using alternative maximum allowable operating pressure.
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure (MAOP) calculated under § 192.620, a segment must meet the following additional design requirements. Records for alternative MAOP must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
§ 192.113   Longitudinal joint factor (E) for steel pipe.
(a) The longitudinal joint factor to be used in the design formula in § 192.105 is determined in accordance with the table 1 to this paragraph (a):
Table 1 to Paragraph ( a )
(b) If the type of longitudinal joint cannot be determined, the joint factor to be used must not exceed that designated for “Other.”
§ 192.115   Temperature derating factor (T) for steel pipe.
The temperature derating factor to be used in the design formula in § 192.105 is determined as follows:
§§ 192.117-192.119   [Reserved]
§ 192.121   Design of plastic pipe.
(a) Design pressure. The design pressure for plastic pipe is determined in accordance with either of the following formulas:
(b) General requirements for plastic pipe and components. (1) Except as provided in paragraphs (c) through (f) of this section, the design pressure for plastic pipe may not exceed a gauge pressure of 100 psig (689 kPa) for pipe used in:
(i) Distribution systems; or
(ii) Transmission lines in Class 3 and 4 locations.
(2) Plastic pipe may not be used where operating temperatures of the pipe will be:
(i) Below −20 °F (−29 °C), or below −40 °F (−40 °C) if all pipe and pipeline components whose operating temperature will be below −20 °F (−29 °C) have a temperature rating by the manufacturer consistent with that operating temperature; or
(ii) Above the temperature at which the HDB used in the design formula under this section is determined.
(3) Unless specified for a particular material in this section, the wall thickness of plastic pipe may not be less than 0.062 inches (1.57 millimeters).
(4) All plastic pipe must have a listed HDB in accordance with PPI TR-4/2012 (incorporated by reference, see § 192.7).
(c) Polyethylene (PE) pipe requirements. (1) For PE pipe produced after July 14, 2004, but before January 22, 2019, a design pressure of up to 125 psig may be used, provided:
(i) The material designation code is PE2406 or PE3408.
(ii) The pipe has a nominal size (Iron Pipe Size (IPS) or Copper Tubing Size (CTS)) of 12 inches or less (above nominal pipe size of 12 inches, the design pressure is limited to 100 psig); and
(iii) The wall thickness is not less than 0.062 inches (1.57 millimeters).
(2) For PE pipe produced on or after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(i) The design pressure does not exceed 125 psig;
(ii) The material designation code is PE2708 or PE4710;
(iii) The pipe has a nominal size (IPS or CTS) of 24 inches or less; and
(iv) The wall thickness for a given outside diameter is not less than that listed in Table 1 to this paragraph (c)(2)(iv):
Table 1 to Paragraph (c)(2)(iv)
(d) Polyamide (PA-11) pipe requirements. (1) For PA-11 pipe produced after January 23, 2009, but before January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(i) The design pressure does not exceed 200 psig;
(ii) The material designation code is PA32312 or PA32316;
(iii) The pipe has a nominal size (IPS or CTS) of 4 inches or less; and
(iv) The pipe has a standard dimension ratio of SDR-11 or less ( i.e., thicker wall pipe).
(2) For PA-11 pipe produced on or after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(i) The design pressure does not exceed 250 psig;
(ii) The material designation code is PA32316;
(iii) The pipe has a nominal size (IPS or CTS) of 6 inches or less; and
(iv) The minimum wall thickness for a given outside diameter is not less than that listed in table 2 to this paragraph (d)(2)(iv):
Table 2 to Paragraph ( d )(2)(iv)
(e) Polyamide (PA-12) pipe requirements. For PA-12 pipe produced after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(1) The design pressure does not exceed 250 psig;
(2) The material designation code is PA42316;
(3) The pipe has a nominal size (IPS or CTS) of 6 inches or less; and
(4) The minimum wall thickness for a given outside diameter is not less than that listed in table 3 to this paragraph (e)(4):
Table 3 to Paragraph ( e )(4)
(f) Reinforced thermosetting plastic pipe requirements. (1) Reinforced thermosetting plastic pipe may not be used at operating temperatures above 150 °F (66 °C).
(2) The wall thickness for reinforced thermosetting plastic pipe may not be less than that listed in the following table:
§ 192.123   [Reserved]
§ 192.125   Design of copper pipe.
(a) Copper pipe used in mains must have a minimum wall thickness of 0.065 inches (1.65 millimeters) and must be hard drawn.
(b) Copper pipe used in service lines must have wall thickness not less than that indicated in the following table:
(c) Copper pipe used in mains and service lines may not be used at pressures in excess of 100 p.s.i. (689 kPa) gage.
(d) Copper pipe that does not have an internal corrosion resistant lining may not be used to carry gas that has an average hydrogen sulfide content of more than 0.3 grains/100 ft 3 (6.9/m 3 ) under standard conditions. Standard conditions refers to 60 °F and 14.7 psia (15.6 °C and one atmosphere) of gas.
§ 192.127   Records: Pipe design.
(a) For steel transmission pipelines installed after July 1, 2020], an operator must collect or make, and retain for the life of the pipeline, records documenting that the pipe is designed to withstand anticipated external pressures and loads in accordance with § 192.103 and documenting that the determination of design pressure for the pipe is made in accordance with § 192.105.
(b) For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting pipe design and the determination of design pressure in accordance with §§ 192.103 and 192.105, operators must retain such records for the life of the pipeline.
(c) For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section.
§ 192.141   Scope.
This subpart prescribes minimum requirements for the design and installation of pipeline components and facilities. In addition, it prescribes requirements relating to protection against accidental overpressuring.
§ 192.143   General requirements.
(a) Each component of a pipeline must be able to withstand operating pressures and other anticipated loadings without impairment of its serviceability with unit stresses equivalent to those allowed for comparable material in pipe in the same location and kind of service. However, if design based upon unit stresses is impractical for a particular component, design may be based upon a pressure rating established by the manufacturer by pressure testing that component or a prototype of the component.
(b) The design and installation of pipeline components and facilities must meet applicable requirements for corrosion control found in subpart I of this part.
(c) Except for excess flow valves, each plastic pipeline component installed after January 22, 2019 must be able to withstand operating pressures and other anticipated loads in accordance with a listed specification.
§ 192.144   Qualifying metallic components.
Notwithstanding any requirement of this subpart which incorporates by reference an edition of a document listed in § 192.7 or Appendix B of this part, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this part if—
(a) It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component; and
(b) The edition of the document under which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in § 192.7 or appendix B of this part:
(1) Pressure testing;
(2) Materials; and
(3) Pressure and temperature ratings.
§ 192.145   Valves.
(a) Except for cast iron and plastic valves, each valve must meet the minimum requirements of API Spec 6D (incorporated by reference, see § 192.7), or to a national or international standard that provides an equivalent performance level. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those requirements.
(b) Each cast iron and plastic valve must comply with the following:
(1) The valve must have a maximum service pressure rating for temperatures that equal or exceed the maximum service temperature.
(2) The valve must be tested as part of the manufacturing, as follows:
(i) With the valve in the fully open position, the shell must be tested with no leakage to a pressure at least 1.5 times the maximum service rating.
(ii) After the shell test, the seat must be tested to a pressure not less than 1.5 times the maximum service pressure rating. Except for swing check valves, test pressure during the seat test must be applied successively on each side of the closed valve with the opposite side open. No visible leakage is permitted.
(iii) After the last pressure test is completed, the valve must be operated through its full travel to demonstrate freedom from interference.
(c) Each valve must be able to meet the anticipated operating conditions.
(d) No valve having shell (body, bonnet, cover, and/or end flange) components made of ductile iron may be used at pressures exceeding 80 percent of the pressure ratings for comparable steel valves at their listed temperature. However, a valve having shell components made of ductile iron may be used at pressures up to 80 percent of the pressure ratings for comparable steel valves at their listed temperature, if:
(1) The temperature-adjusted service pressure does not exceed 1,000 p.s.i. (7 Mpa) gage; and
(2) Welding is not used on any ductile iron component in the fabrication of the valve shells or their assembly.
(e) No valve having shell (body, bonnet, cover, and/or end flange) components made of cast iron, malleable iron, or ductile iron may be used in the gas pipe components of compressor stations.
(f) Except for excess flow valves, plastic valves installed after January 22, 2019, must meet the minimum requirements of a listed specification. A valve may not be used under operating conditions that exceed the applicable pressure and temperature ratings contained in the listed specification.
§ 192.147   Flanges and flange accessories.
(a) Each flange or flange accessory (other than cast iron) must meet the minimum requirements of ASME/ANSI B16.5 (incorporated by reference, see § 192.7), ANSI/MSS SP-44 (incorporation by reference, see § 192.7), or the equivalent.
(b) Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service.
(c) Each flange on a flanged joint in cast iron pipe must conform in dimensions, drilling, face and gasket design to ASME/ANSI B16.1 (incorporated by reference, see § 192.7)and be cast integrally with the pipe, valve, or fitting.
§ 192.149   Standard fittings.
(a) The minimum metal thickness of threaded fittings may not be less than specified for the pressures and temperatures in the applicable standards referenced in this part, or their equivalent.
(b) Each steel butt-welding fitting must have pressure and temperature ratings based on stresses for pipe of the same or equivalent material. The actual bursting strength of the fitting must at least equal the computed bursting strength of pipe of the designated material and wall thickness, as determined by a prototype that was tested to at least the pressure required for the pipeline to which it is being added.
(c) Plastic fittings installed after January 22, 2019, must meet a listed specification.
§ 192.150   Passage of internal inspection devices.
(a) Except as provided in paragraphs (b) and (c) of this section, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line, must be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102, section 7 (incorporated by reference, see § 192.7).
(b) This section does not apply to: (1) Manifolds;
(2) Station piping such as at compressor stations, meter stations, or regulator stations;
(3) Piping associated with storage facilities, other than a continuous run of transmission line between a compressor station and storage facilities;
(4) Cross-overs;
(5) Sizes of pipe for which an instrumented internal inspection device is not commercially available;
(6) Transmission lines, operated in conjunction with a distribution system which are installed in Class 4 locations;
(7) Offshore transmission lines, except transmission lines 10 3/4 inches (273 millimeters) or more in outside diameter on which construction begins after December 28, 2005, that run from platform to platform or platform to shore unless—
(i) Platform space or configuration is incompatible with launching or retrieving instrumented internal inspection devices; or
(ii) If the design includes taps for lateral connections, the operator can demonstrate, based on investigation or experience, that there is no reasonably practical alternative under the design circumstances to the use of a tap that will obstruct the passage of instrumented internal inspection devices;
(8) Gathering lines; and
(9) Other piping that, under § 190.9 of this chapter, the Administrator finds in a particular case would be impracticable to design and construct to accommodate the passage of instrumented internal inspection devices.
(c) An operator encountering emergencies, construction time constraints or other unforeseen construction problems need not construct a new or replacement segment of a transmission line to meet paragraph (a) of this section, if the operator determines and documents why an impracticability prohibits compliance with paragraph (a) of this section. Within 30 days after discovering the emergency or construction problem the operator must petition, under § 190.9 of this chapter, for approval that design and construction to accommodate passage of instrumented internal inspection devices would be impracticable. If the petition is denied, within 1 year after the date of the notice of the denial, the operator must modify that segment to allow passage of instrumented internal inspection devices.
§ 192.151   Tapping.
(a) Each mechanical fitting used to make a hot tap must be designed for at least the operating pressure of the pipeline.
(b) Where a ductile iron pipe is tapped, the extent of full-thread engagement and the need for the use of outside-sealing service connections, tapping saddles, or other fixtures must be determined by service conditions.
(c) Where a threaded tap is made in cast iron or ductile iron pipe, the diameter of the tapped hole may not be more than 25 percent of the nominal diameter of the pipe unless the pipe is reinforced, except that
(1) Existing taps may be used for replacement service, if they are free of cracks and have good threads; and
(2) A 1 1/4 -inch (32 millimeters) tap may be made in a 4-inch (102 millimeters) cast iron or ductile iron pipe, without reinforcement.
§ 192.153   Components fabricated by welding.
(a) Except for branch connections and assemblies of standard pipe and fittings joined by circumferential welds, the design pressure of each component fabricated by welding, whose strength cannot be determined, must be established in accordance with paragraph UG-101 of the ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1) (incorporated by reference, see § 192.7).
(b) Each prefabricated unit that uses plate and longitudinal seams must be designed, constructed, and tested in accordance with the ASME BPVC ( Rules for Construction of Pressure Vessels as defined in either Section VIII, Division 1 or Section VIII, Division 2; incorporated by reference, see § 192.7), except for the following:
(1) Regularly manufactured butt-welding fittings.
(2) Pipe that has been produced and tested under a specification listed in appendix B to this part.
(3) Partial assemblies such as split rings or collars.
(4) Prefabricated units that the manufacturer certifies have been tested to at least twice the maximum pressure to which they will be subjected under the anticipated operating conditions.
(c) Orange-peel bull plugs and orange-peel swages may not be used on pipelines that are to operate at a hoop stress of 20 percent or more of the SMYS of the pipe.
(d) Except for flat closures designed in accordance with ASME BPVC, Section VIII, Division 1 or Division 2, (both incorporated by reference, see § 192.7), flat closures and fish tails may not be used on pipe that either operates at 100 psig (689 kilopascals) or more, or that is more than 3 inches (76 millimeters) in nominal diameter.
(e) The test requirements for a prefabricated unit or pressure vessel, defined for this paragraph as components with a design pressure established in accordance with paragraph (a) or paragraph (b) of this section are as follows.
(1) A prefabricated unit or pressure vessel installed after July 14, 2004 is not subject to the strength testing requirements at § 192.505(b) provided the component has been tested in accordance with paragraph (a) or paragraph (b) of this section and with a test factor of at least 1.3 times MAOP.
(2) A prefabricated unit or pressure vessel must be tested for a duration specified as follows:
(i) A prefabricated unit or pressure vessel installed after July 14, 2004, but before October 1, 2021 is exempt from §§ 192.505(c) and (d) and 192.507(c) provided it has been tested for a duration consistent with the ASME BPVC requirements referenced in paragraph (a) or (b) of this section.
(ii) A prefabricated unit or pressure vessel installed on or after October 1, 2021 must be tested for the duration specified in either § 192.505(c) or (d), § 192.507(c), or § 192.509(a), whichever is applicable for the pipeline in which the component is being installed.
(3) For any prefabricated unit or pressure vessel permanently or temporarily installed on a pipeline facility, an operator must either:
(i) Test the prefabricated unit or pressure vessel in accordance with this section and Subpart J of this part after it has been placed on its support structure at its final installation location. The test may be performed before or after it has been tied-in to the pipeline. Test records that meet § 192.517(a) must be kept for the operational life of the prefabricated unit or pressure vessel; or
(ii) For a prefabricated unit or pressure vessel that is pressure tested prior to installation or where a manufacturer's pressure test is used in accordance with paragraph (e) of this section, inspect the prefabricated unit or pressure vessel after it has been placed on its support structure at its final installation location and confirm that the prefabricated unit or pressure vessel was not damaged during any prior operation, transportation, or installation into the pipeline. The inspection procedure and documented inspection must include visual inspection for vessel damage, including, at a minimum, inlets, outlets, and lifting locations. Injurious defects that are an integrity threat may include dents, gouges, bending, corrosion, and cracking. This inspection must be performed prior to operation but may be performed either before or after it has been tied-in to the pipeline. If injurious defects that are an integrity threat are found, the prefabricated unit or pressure vessel must be either non-destructively tested, re-pressure tested, or remediated in accordance with applicable part 192 requirements for a fabricated unit or with the applicable ASME BPVC requirements referenced in paragraphs (a) or (b) of this section. Test, inspection, and repair records for the fabricated unit or pressure vessel must be kept for the operational life of the component. Test records must meet the requirements in § 192.517(a).
(4) An initial pressure test from the prefabricated unit or pressure vessel manufacturer may be used to meet the requirements of this section with the following conditions:
(i) The prefabricated unit or pressure vessel is newly-manufactured and installed on or after October 1, 2021, except as provided in paragraph (e)(4)(ii) of this section.
(ii) An initial pressure test from the fabricated unit or pressure vessel manufacturer or other prior test of a new or existing prefabricated unit or pressure vessel may be used for a component that is temporarily installed in a pipeline facility in order to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement. The temporary component must be promptly removed after that task is completed. If operational and environmental constraints require leaving a temporary prefabricated unit or pressure vessel under this paragraph in place for longer than 30 days, the operator must notify PHMSA and State or local pipeline safety authorities, as applicable, in accordance with § 192.18.
(iii) The manufacturer's pressure test must meet the minimum requirements of this part; and
(iv) The operator inspects and remediates the prefabricated unit or pressure vessel after installation in accordance with paragraph (e)(3)(ii) of this section.
(5) An existing prefabricated unit or pressure vessel that is temporarily removed from a pipeline facility to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement, and then re-installed at the same location must be inspected in accordance with paragraph (e)(3)(ii) of this section; however, a new pressure test is not required provided no damage or threats to the operational integrity of the prefabricated unit or pressure vessel were identified during the inspection and the MAOP of the pipeline is not increased.
(6) Except as provided in paragraphs (e)(4)(ii) and (5) of this section, on or after October 1, 2021, an existing prefabricated unit or pressure vessel relocated and operated at a different location must meet the requirements of this part and the following:
(i) The prefabricated unit or pressure vessel must be designed and constructed in accordance with the requirements of this part at the time the vessel is returned to operational service at the new location; and
(ii) The prefabricated unit or pressure vessel must be pressure tested by the operator in accordance with the testing and inspection requirements of this part applicable to newly installed prefabricated units and pressure vessels.
§ 192.155   Welded branch connections.
Each welded branch connection made to pipe in the form of a single connection, or in a header or manifold as a series of connections, must be designed to ensure that the strength of the pipeline system is not reduced, taking into account the stresses in the remaining pipe wall due to the opening in the pipe or header, the shear stresses produced by the pressure acting on the area of the branch opening, and any external loadings due to thermal movement, weight, and vibration.
§ 192.157   Extruded outlets.
Each extruded outlet must be suitable for anticipated service conditions and must be at least equal to the design strength of the pipe and other fittings in the pipeline to which it is attached.
§ 192.159   Flexibility.
Each pipeline must be designed with enough flexibility to prevent thermal expansion or contraction from causing excessive stresses in the pipe or components, excessive bending or unusual loads at joints, or undesirable forces or moments at points of connection to equipment, or at anchorage or guide points.
§ 192.161   Supports and anchors.
(a) Each pipeline and its associated equipment must have enough anchors or supports to:
(1) Prevent undue strain on connected equipment;
(2) Resist longitudinal forces caused by a bend or offset in the pipe; and
(3) Prevent or damp out excessive vibration.
(b) Each exposed pipeline must have enough supports or anchors to protect the exposed pipe joints from the maximum end force caused by internal pressure and any additional forces caused by temperature expansion or contraction or by the weight of the pipe and its contents.
(c) Each support or anchor on an exposed pipeline must be made of durable, noncombustible material and must be designed and installed as follows:
(1) Free expansion and contraction of the pipeline between supports or anchors may not be restricted.
(2) Provision must be made for the service conditions involved.
(3) Movement of the pipeline may not cause disengagement of the support equipment.
(d) Each support on an exposed pipeline operated at a stress level of 50 percent or more of SMYS must comply with the following:
(1) A structural support may not be welded directly to the pipe.
(2) The support must be provided by a member that completely encircles the pipe.
(3) If an encircling member is welded to a pipe, the weld must be continuous and cover the entire circumference.
(e) Each underground pipeline that is connected to a relatively unyielding line or other fixed object must have enough flexibility to provide for possible movement, or it must have an anchor that will limit the movement of the pipeline.
(f) Except for offshore pipelines, each underground pipeline that is being connected to new branches must have a firm foundation for both the header and the branch to prevent detrimental lateral and vertical movement.
§ 192.163   Compressor stations: Design and construction.
(a) Location of compressor building. Except for a compressor building on a platform located offshore or in inland navigable waters, each main compressor building of a compressor station must be located on property under the control of the operator. It must be far enough away from adjacent property, not under control of the operator, to minimize the possibility of fire being communicated to the compressor building from structures on adjacent property. There must be enough open space around the main compressor building to allow the free movement of fire-fighting equipment.
(b) Building construction. Each building on a compressor station site must be made of noncombustible materials if it contains either—
(1) Pipe more than 2 inches (51 millimeters) in diameter that is carrying gas under pressure; or
(2) Gas handling equipment other than gas utilization equipment used for domestic purposes.
(c) Exits. Each operating floor of a main compressor building must have at least two separated and unobstructed exits located so as to provide a convenient possibility of escape and an unobstructed passage to a place of safety. Each door latch on an exit must be of a type which can be readily opened from the inside without a key. Each swinging door located in an exterior wall must be mounted to swing outward.
(d) Fenced areas. Each fence around a compressor station must have at least two gates located so as to provide a convenient opportunity for escape to a place of safety, or have other facilities affording a similarly convenient exit from the area. Each gate located within 200 feet (61 meters) of any compressor plant building must open outward and, when occupied, must be openable from the inside without a key.
(e) Electrical facilities. Electrical equipment and wiring installed in compressor stations must conform to the NFPA 70 (incorporated by reference, see § 192.7), so far as that code is applicable.
§ 192.165   Compressor stations: Liquid removal.
(a) Where entrained vapors in gas may liquefy under the anticipated pressure and temperature conditions, the compressor must be protected against the introduction of those liquids in quantities that could cause damage.
(b) Each liquid separator used to remove entrained liquids at a compressor station must:
(1) Have a manually operable means of removing these liquids.
(2) Where slugs of liquid could be carried into the compressors, have either automatic liquid removal facilities, an automatic compressor shutdown device, or a high liquid level alarm; and
(3) Be manufactured in accordance with section VIII ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see § 192.7) and the additional requirements of § 192.153(e) except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4, or less.
§ 192.167   Compressor stations: Emergency shutdown.
(a) Except for unattended field compressor stations of 1,000 horsepower (746 kilowatts) or less, each compressor station must have an emergency shutdown system that meets the following:
(1) It must be able to block gas out of the station and blow down the station piping.
(2) It must discharge gas from the blowdown piping at a location where the gas will not create a hazard.
(3) It must provide means for the shutdown of gas compressing equipment, gas fires, and electrical facilities in the vicinity of gas headers and in the compressor building, except that:
(i) Electrical circuits that supply emergency lighting required to assist station personnel in evacuating the compressor building and the area in the vicinity of the gas headers must remain energized; and
(ii) Electrical circuits needed to protect equipment from damage may remain energized.
(4) It must be operable from at least two locations, each of which is:
(i) Outside the gas area of the station;
(ii) Near the exit gates, if the station is fenced, or near emergency exits, if not fenced; and
(iii) Not more than 500 feet (153 meters) from the limits of the station.
(b) If a compressor station supplies gas directly to a distribution system with no other adequate source of gas available, the emergency shutdown system must be designed so that it will not function at the wrong time and cause an unintended outage on the distribution system.
(c) On a platform located offshore or in inland navigable waters, the emergency shutdown system must be designed and installed to actuate automatically by each of the following events:
(1) In the case of an unattended compressor station:
(i) When the gas pressure equals the maximum allowable operating pressure plus 15 percent; or
(ii) When an uncontrolled fire occurs on the platform; and
(2) In the case of a compressor station in a building:
(i) When an uncontrolled fire occurs in the building; or
(ii) When the concentration of gas in air reaches 50 percent or more of the lower explosive limit in a building which has a source of ignition.
§ 192.169   Compressor stations: Pressure limiting devices.
(a) Each compressor station must have pressure relief or other suitable protective devices of sufficient capacity and sensitivity to ensure that the maximum allowable operating pressure of the station piping and equipment is not exceeded by more than 10 percent.
(b) Each vent line that exhausts gas from the pressure relief valves of a compressor station must extend to a location where the gas may be discharged without hazard.
§ 192.171   Compressor stations: Additional safety equipment.
(a) Each compressor station must have adequate fire protection facilities. If fire pumps are a part of these facilities, their operation may not be affected by the emergency shutdown system.
(b) Each compressor station prime mover, other than an electrical induction or synchronous motor, must have an automatic device to shut down the unit before the speed of either the prime mover or the driven unit exceeds a maximum safe speed.
(c) Each compressor unit in a compressor station must have a shutdown or alarm device that operates in the event of inadequate cooling or lubrication of the unit.
(d) Each compressor station gas engine that operates with pressure gas injection must be equipped so that stoppage of the engine automatically shuts off the fuel and vents the engine distribution manifold.
(e) Each muffler for a gas engine in a compressor station must have vent slots or holes in the baffles of each compartment to prevent gas from being trapped in the muffler.
§ 192.173   Compressor stations: Ventilation.
Each compressor station building must be ventilated to ensure that employees are not endangered by the accumulation of gas in rooms, sumps, attics, pits, or other enclosed places.
§ 192.175   Pipe-type and bottle-type holders.
(a) Each pipe-type and bottle-type holder must be designed so as to prevent the accumulation of liquids in the holder, in connecting pipe, or in auxiliary equipment, that might cause corrosion or interfere with the safe operation of the holder.
(b) Each pipe-type or bottle-type holder must have minimum clearance from other holders in accordance with the following formula:
§ 192.177   Additional provisions for bottle-type holders.
(a) Each bottle-type holder must be—
(1) Located on a site entirely surrounded by fencing that prevents access by unauthorized persons and with minimum clearance from the fence as follows:
(2) Designed using the design factors set forth in § 192.111; and
(3) Buried with a minimum cover in accordance with § 192.327.
(b) Each bottle-type holder manufactured from steel that is not weldable under field conditions must comply with the following:
(1) A bottle-type holder made from alloy steel must meet the chemical and tensile requirements for the various grades of steel in ASTM A372/372M (incorporated by reference, see § 192.7).
(2) The actual yield-tensile ratio of the steel may not exceed 0.85.
(3) Welding may not be performed on the holder after it has been heat treated or stress relieved, except that copper wires may be attached to the small diameter portion of the bottle end closure for cathodic protection if a localized thermit welding process is used.
(4) The holder must be given a mill hydrostatic test at a pressure that produces a hoop stress at least equal to 85 percent of the SMYS.
(5) The holder, connection pipe, and components must be leak tested after installation as required by subpart J of this part.
§ 192.179   Transmission line valves.
(a) Each transmission line, other than offshore segments, must have sectionalizing block valves spaced as follows, unless in a particular case the Administrator finds that alternative spacing would provide an equivalent level of safety:
(1) Each point on the pipeline in a Class 4 location must be within 2 1/2 miles (4 kilometers)of a valve.
(2) Each point on the pipeline in a Class 3 location must be within 4 miles (6.4 kilometers) of a valve.
(3) Each point on the pipeline in a Class 2 location must be within 7 1/2 miles (12 kilometers) of a valve.
(4) Each point on the pipeline in a Class 1 location must be within 10 miles (16 kilometers) of a valve.
(b) Each sectionalizing block valve on a transmission line, other than offshore segments, must comply with the following:
(1) The valve and the operating device to open or close the valve must be readily accessible and protected from tampering and damage.
(2) The valve must be supported to prevent settling of the valve or movement of the pipe to which it is attached.
(c) Each section of a transmission line, other than offshore segments, between main line valves must have a blowdown valve with enough capacity to allow the transmission line to be blown down as rapidly as practicable. Each blowdown discharge must be located so the gas can be blown to the atmosphere without hazard and, if the transmission line is adjacent to an overhead electric line, so that the gas is directed away from the electrical conductors.
(d) Offshore segments of transmission lines must be equipped with valves or other components to shut off the flow of gas to an offshore platform in an emergency.
(e) For onshore transmission pipeline segments with diameters greater than or equal to 6 inches that are constructed after April 10, 2023, the operator must install rupture-mitigation valves (RMV) or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph (g) of this section. All RMVs and alternative equivalent technologies installed pursuant to this paragraph (e) must meet the requirements of § 192.636. The installation requirements in this paragraph (e) do not apply to pipe segments with a potential impact radius (PIR), as defined in § 192.903, that is less than or equal to 150 feet in either Class 1 or Class 2 locations. An operator may request an extension of the installation compliance deadline requirements of this paragraph (e) if it can demonstrate to PHMSA, in accordance with the notification procedures in § 192.18, that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular new pipeline.
(f) For entirely replaced onshore transmission pipeline segments, as defined in § 192.3, with diameters greater than or equal to 6 inches and that are installed after April 10, 2023, the operator must install RMVs or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph (g) of this section. All RMVs and alternative equivalent technologies installed pursuant to this paragraph (f) must meet the requirements of § 192.636. The requirements of this paragraph (f) apply when the applicable pipeline replacement project involves a valve, either through addition, replacement, or removal. The installation requirements in this paragraph (f) do not apply to pipe segments with a PIR, as defined in § 192.903, that is less than or equal to 150 feet in either Class 1 or Class 2 locations. An operator may request an extension of the installation compliance deadline requirements of this paragraph (f) if it can demonstrate to PHMSA, in accordance with the notification procedures in § 192.18, that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular pipeline replacement project.
(g) If an operator elects to use alternative equivalent technology in accordance with paragraph (e) or (f) of this section, the operator must notify PHMSA in accordance with the procedures in § 192.18. The operator must include a technical and safety evaluation in its notice to PHMSA. Valves that are installed as alternative equivalent technology must comply with §§ 192.634 and 192.636. An operator requesting use of manual valves as an alternative equivalent technology must also include within the notification submitted to PHMSA a demonstration that installation of an RMV as otherwise required would be economically, technically, or operationally infeasible. An operator may use a manual compressor station valve at a continuously manned station as an alternative equivalent technology, and use of such valve would not require a notification to PHMSA in accordance with § 192.18, but it must comply with § 192.636.
(h) The valve spacing requirements of paragraph (a) of this section do not apply to pipe replacements on a pipeline if the distance between each point on the pipeline and the nearest valve does not exceed:
(1) Four (4) miles in Class 4 locations, with a total spacing between valves no greater than 8 miles;
(2) Seven-and-a-half (7 1/2 ) miles in Class 3 locations, with a total spacing between valves no greater than 15 miles; or
(3) Ten (10) miles in Class 1 or 2 locations, with a total spacing between valves no greater than 20 miles.
§ 192.181   Distribution line valves.
(a) Each high-pressure distribution system must have valves spaced so as to reduce the time to shut down a section of main in an emergency. The valve spacing is determined by the operating pressure, the size of the mains, and the local physical conditions.
(b) Each regulator station controlling the flow or pressure of gas in a distribution system must have a valve installed on the inlet piping at a distance from the regulator station sufficient to permit the operation of the valve during an emergency that might preclude access to the station.
(c) Each valve on a main installed for operating or emergency purposes must comply with the following:
(1) The valve must be placed in a readily accessible location so as to facilitate its operation in an emergency.
(2) The operating stem or mechanism must be readily accessible.
(3) If the valve is installed in a buried box or enclosure, the box or enclosure must be installed so as to avoid transmitting external loads to the main.
§ 192.183   Vaults: Structural design requirements.
(a) Each underground vault or pit for valves, pressure relieving, pressure limiting, or pressure regulating stations, must be able to meet the loads which may be imposed upon it, and to protect installed equipment.
(b) There must be enough working space so that all of the equipment required in the vault or pit can be properly installed, operated, and maintained.
(c) Each pipe entering, or within, a regulator vault or pit must be steel for sizes 10 inch (254 millimeters), and less, except that control and gage piping may be copper. Where pipe extends through the vault or pit structure, provision must be made to prevent the passage of gases or liquids through the opening and to avert strains in the pipe.
§ 192.185   Vaults: Accessibility.
Each vault must be located in an accessible location and, so far as practical, away from:
(a) Street intersections or points where traffic is heavy or dense;
(b) Points of minimum elevation, catch basins, or places where the access cover will be in the course of surface waters; and
(c) Water, electric, steam, or other facilities.
§ 192.187   Vaults: Sealing, venting, and ventilation.
Each underground vault or closed top pit containing either a pressure regulating or reducing station, or a pressure limiting or relieving station, must be sealed, vented or ventilated as follows:
(a) When the internal volume exceeds 200 cubic feet (5.7 cubic meters):
(1) The vault or pit must be ventilated with two ducts, each having at least the ventilating effect of a pipe 4 inches (102 millimeters) in diameter;
(2) The ventilation must be enough to minimize the formation of combustible atmosphere in the vault or pit; and
(3) The ducts must be high enough above grade to disperse any gas-air mixtures that might be discharged.
(b) When the internal volume is more than 75 cubic feet (2.1 cubic meters) but less than 200 cubic feet (5.7 cubic meters):
(1) If the vault or pit is sealed, each opening must have a tight fitting cover without open holes through which an explosive mixture might be ignited, and there must be a means for testing the internal atmosphere before removing the cover;
(2) If the vault or pit is vented, there must be a means of preventing external sources of ignition from reaching the vault atmosphere; or
(3) If the vault or pit is ventilated, paragraph (a) or (c) of this section applies.
(c) If a vault or pit covered by paragraph (b) of this section is ventilated by openings in the covers or gratings and the ratio of the internal volume, in cubic feet, to the effective ventilating area of the cover or grating, in square feet, is less than 20 to 1, no additional ventilation is required.
§ 192.189   Vaults: Drainage and waterproofing.
(a) Each vault must be designed so as to minimize the entrance of water.
(b) A vault containing gas piping may not be connected by means of a drain connection to any other underground structure.
(c) Electrical equipment in vaults must conform to the applicable requirements of Class 1, Group D, of the National Electrical Code, NFPA-70 (incorporated by reference, see § 192.7).
§ 192.191   [Reserved]
§ 192.193   Valve installation in plastic pipe.
Each valve installed in plastic pipe must be designed so as to protect the plastic material against excessive torsional or shearing loads when the valve or shutoff is operated, and from any other secondary stresses that might be exerted through the valve or its enclosure.
§ 192.195   Protection against accidental overpressuring.
(a) General requirements. Except as provided in § 192.197, each pipeline that is connected to a gas source so that the maximum allowable operating pressure could be exceeded as the result of pressure control failure or of some other type of failure, must have pressure relieving or pressure limiting devices that meet the requirements of §§ 192.199 and 192.201.
(b) Additional requirements for distribution systems. Each distribution system that is supplied from a source of gas that is at a higher pressure than the maximum allowable operating pressure for the system must—
(1) Have pressure regulation devices capable of meeting the pressure, load, and other service conditions that will be experienced in normal operation of the system, and that could be activated in the event of failure of some portion of the system; and
(2) Be designed so as to prevent accidental overpressuring.
§ 192.197   Control of the pressure of gas delivered from high-pressure distribution systems.
(a) If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less and a service regulator having the following characteristics is used, no other pressure limiting device is required:
(1) A regulator capable of reducing distribution line pressure to pressures recommended for household appliances.
(2) A single port valve with proper orifice for the maximum gas pressure at the regulator inlet.
(3) A valve seat made of resilient material designed to withstand abrasion of the gas, impurities in gas, cutting by the valve, and to resist permanent deformation when it is pressed against the valve port.
(4) Pipe connections to the regulator not exceeding 2 inches (51 millimeters) in diameter.
(5) A regulator that, under normal operating conditions, is able to regulate the downstream pressure within the necessary limits of accuracy and to limit the build-up of pressure under no-flow conditions to prevent a pressure that would cause the unsafe operation of any connected and properly adjusted gas utilization equipment.
(6) A self-contained service regulator with no external static or control lines.
(b) If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator that does not have all of the characteristics listed in paragraph (a) of this section is used, or if the gas contains materials that seriously interfere with the operation of service regulators, there must be suitable protective devices to prevent unsafe overpressuring of the customer's appliances if the service regulator fails.
(c) If the maximum actual operating pressure of the distribution system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods must be used to regulate and limit, to the maximum safe value, the pressure of gas delivered to the customer:
(1) A service regulator having the characteristics listed in paragraph (a) of this section, and another regulator located upstream from the service regulator. The upstream regulator may not be set to maintain a pressure higher than 60 p.s.i. (414 kPa) gage. A device must be installed between the upstream regulator and the service regulator to limit the pressure on the inlet of the service regulator to 60 p.s.i. (414 kPa) gage or less in case the upstream regulator fails to function properly. This device may be either a relief valve or an automatic shutoff that shuts, if the pressure on the inlet of the service regulator exceeds the set pressure (60 p.s.i. (414 kPa) gage or less), and remains closed until manually reset.
(2) A service regulator and a monitoring regulator set to limit, to a maximum safe value, the pressure of the gas delivered to the customer.
(3) A service regulator with a relief valve vented to the outside atmosphere, with the relief valve set to open so that the pressure of gas going to the customer does not exceed a maximum safe value. The relief valve may either be built into the service regulator or it may be a separate unit installed downstream from the service regulator. This combination may be used alone only in those cases where the inlet pressure on the service regulator does not exceed the manufacturer's safe working pressure rating of the service regulator, and may not be used where the inlet pressure on the service regulator exceeds 125 p.s.i. (862 kPa) gage. For higher inlet pressures, the methods in paragraph (c) (1) or (2) of this section must be used.
(4) A service regulator and an automatic shutoff device that closes upon a rise in pressure downstream from the regulator and remains closed until manually reset.
§ 192.199   Requirements for design of pressure relief and limiting devices.
Except for rupture discs, each pressure relief or pressure limiting device must:
(a) Be constructed of materials such that the operation of the device will not be impaired by corrosion;
(b) Have valves and valve seats that are designed not to stick in a position that will make the device inoperative;
(c) Be designed and installed so that it can be readily operated to determine if the valve is free, can be tested to determine the pressure at which it will operate, and can be tested for leakage when in the closed position;
(d) Have support made of noncombustible material;
(e) Have discharge stacks, vents, or outlet ports designed to prevent accumulation of water, ice, or snow, located where gas can be discharged into the atmosphere without undue hazard;
(f) Be designed and installed so that the size of the openings, pipe, and fittings located between the system to be protected and the pressure relieving device, and the size of the vent line, are adequate to prevent hammering of the valve and to prevent impairment of relief capacity;
(g) Where installed at a district regulator station to protect a pipeline system from overpressuring, be designed and installed to prevent any single incident such as an explosion in a vault or damage by a vehicle from affecting the operation of both the overpressure protective device and the district regulator; and
(h) Except for a valve that will isolate the system under protection from its source of pressure, be designed to prevent unauthorized operation of any stop valve that will make the pressure relief valve or pressure limiting device inoperative.
§ 192.201   Required capacity of pressure relieving and limiting stations.
(a) Each pressure relief station or pressure limiting station or group of those stations installed to protect a pipeline must have enough capacity, and must be set to operate, to insure the following:
(1) In a low pressure distribution system, the pressure may not cause the unsafe operation of any connected and properly adjusted gas utilization equipment.
(2) In pipelines other than a low pressure distribution system:
(i) If the maximum allowable operating pressure is 60 p.s.i. (414 kPa) gage or more, the pressure may not exceed the maximum allowable operating pressure plus 10 percent, or the pressure that produces a hoop stress of 75 percent of SMYS, whichever is lower;
(ii) If the maximum allowable operating pressure is 12 p.s.i. (83 kPa) gage or more, but less than 60 p.s.i. (414 kPa) gage, the pressure may not exceed the maximum allowable operating pressure plus 6 p.s.i. (41 kPa) gage; or
(iii) If the maximum allowable operating pressure is less than 12 p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable operating pressure plus 50 percent.
(b) When more than one pressure regulating or compressor station feeds into a pipeline, relief valves or other protective devices must be installed at each station to ensure that the complete failure of the largest capacity regulator or compressor, or any single run of lesser capacity regulators or compressors in that station, will not impose pressures on any part of the pipeline or distribution system in excess of those for which it was designed, or against which it was protected, whichever is lower.
(c) Relief valves or other pressure limiting devices must be installed at or near each regulator station in a low-pressure distribution system, with a capacity to limit the maximum pressure in the main to a pressure that will not exceed the safe operating pressure for any connected and properly adjusted gas utilization equipment.
§ 192.203   Instrument, control, and sampling pipe and components.
(a) Applicability. This section applies to the design of instrument, control, and sampling pipe and components. It does not apply to permanently closed systems, such as fluid-filled temperature-responsive devices.
(b) Materials and design. All materials employed for pipe and components must be designed to meet the particular conditions of service and the following:
(1) Each takeoff connection and attaching boss, fitting, or adapter must be made of suitable material, be able to withstand the maximum service pressure and temperature of the pipe or equipment to which it is attached, and be designed to satisfactorily withstand all stresses without failure by fatigue.
(2) Except for takeoff lines that can be isolated from sources of pressure by other valving, a shutoff valve must be installed in each takeoff line as near as practicable to the point of takeoff. Blowdown valves must be installed where necessary.
(3) Brass or copper material may not be used for metal temperatures greater than 400 °F (204 °C).
(4) Pipe or components that may contain liquids must be protected by heating or other means from damage due to freezing.
(5) Pipe or components in which liquids may accumulate must have drains or drips.
(6) Pipe or components subject to clogging from solids or deposits must have suitable connections for cleaning.
(7) The arrangement of pipe, components, and supports must provide safety under anticipated operating stresses.
(8) Each joint between sections of pipe, and between pipe and valves or fittings, must be made in a manner suitable for the anticipated pressure and temperature condition. Slip type expansion joints may not be used. Expansion must be allowed for by providing flexibility within the system itself.
(9) Each control line must be protected from anticipated causes of damage and must be designed and installed to prevent damage to any one control line from making both the regulator and the over-pressure protective device inoperative.
§ 192.204   Risers installed after January 22, 2019.
(a) Riser designs must be tested to ensure safe performance under anticipated external and internal loads acting on the assembly.
(b) Factory assembled anodeless risers must be designed and tested in accordance with ASTM F1973-13 (incorporated by reference, see § 192.7).
(c) All risers used to connect regulator stations to plastic mains must be rigid and designed to provide adequate support and resist lateral movement. Anodeless risers used in accordance with this paragraph must have a rigid riser casing.
§ 192.205   Records: Pipeline components.
(a) For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with this subpart. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches must have records documenting the manufacturing specification in effect at the time of manufacture, including yield strength, ultimate tensile strength, and chemical composition of materials.
(b) For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting the manufacturing standard and pressure rating for valves, flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches, operators must retain such records for the life of the pipeline.
(c) For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section.
§ 192.221   Scope.
(a) This subpart prescribes minimum requirements for welding steel materials in pipelines.
(b) This subpart does not apply to welding that occurs during the manufacture of steel pipe or steel pipeline components.
§ 192.225   Welding procedures.
(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5 (except for Note 2 in section 5.4.2.2), section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 192.7), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see § 192.7) to produce welds meeting the requirements of this subpart. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the applicable welding standard(s).
(b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used.
§ 192.227   Qualification of welders and welding operators.
(a) Except as provided in paragraph (b) of this section, each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 192.7), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see § 192.7). However, a welder or welding operator qualified under an earlier edition than the listed in § 192.7 of this part may weld but may not requalify under that earlier edition.
(b) A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of Appendix C of this part. Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of this part as a requirement of the qualifying test.
(c) For steel transmission pipe installed after July 1, 2021, records demonstrating each individual welder qualification at the time of construction in accordance with this section must be retained for a minimum of 5 years following construction.
§ 192.229   Limitations on welders and welding operators.
(a) No welder or welding operator whose qualification is based on nondestructive testing may weld compressor station pipe and components.
(b) A welder or welding operator may not weld with a particular welding process unless, within the preceding 6 calendar months, the welder or welding operator was engaged in welding with that process. Alternatively, welders or welding operators may demonstrate they have engaged in a specific welding process if they have performed a weld with that process that was tested and found acceptable under section 6, 9, 12, or Appendix A of API Std 1104 (incorporated by reference, see § 192.7) within the preceding 7 1/2 months.
(c) A welder or welding operator qualified under § 192.227(a)—
(1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under either section 6, section 9, section 12 or Appendix A of API Std 1104 (incorporated by reference, see § 192.7). Alternatively, welders or welding operators may maintain an ongoing qualification status by performing welds tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding 7 1/2 months. A welder or welding operator qualified under an earlier edition of a standard listed in § 192.7 of this part may weld, but may not re-qualify under that earlier edition; and,
(2) May not weld on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS unless the welder or welding operator is tested in accordance with paragraph (c)(1) of this section or re-qualifies under paragraph (d)(1) or (d)(2) of this section.
(d) A welder or welding operator qualified under § 192.227(b) may not weld unless—
(1) Within the preceding 15 calendar months, but at least once each calendar year, the welder or welding operator has re-qualified under § 192.227(b); or
(2) Within the preceding 7 1/2 calendar months, but at least twice each calendar year, the welder or welding operator has had—
(i) A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or
(ii) For a welder who works only on service lines 2 inches (51 millimeters) or smaller in diameter, the welder has had two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part.
§ 192.231   Protection from weather.
The welding operation must be protected from weather conditions that would impair the quality of the completed weld.
§ 192.233   Miter joints.
(a) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 30 percent or more of SMYS may not deflect the pipe more than 3°.
(b) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of less than 30 percent, but more than 10 percent, of SMYS may not deflect the pipe more than 12 1/2 ° and must be a distance equal to one pipe diameter or more away from any other miter joint, as measured from the crotch of each joint.
(c) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 10 percent or less of SMYS may not deflect the pipe more than 90°.
§ 192.235   Preparation for welding.
Before beginning any welding, the welding surfaces must be clean and free of any material that may be detrimental to the weld, and the pipe or component must be aligned to provide the most favorable condition for depositing the root bead. This alignment must be preserved while the root bead is being deposited.
§ 192.241   Inspection and test of welds.
(a) Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that:
(1) The welding is performed in accordance with the welding procedure; and
(2) The weld is acceptable under paragraph (c) of this section.
(b) The welds on a pipeline to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS must be nondestructively tested in accordance with § 192.243, except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if:
(1) The pipe has a nominal diameter of less than 6 inches (152 millimeters); or
(2) The pipeline is to be operated at a pressure that produces a hoop stress of less than 40 percent of SMYS and the welds are so limited in number that nondestructive testing is impractical.
(c) The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by reference, see § 192.7). Appendix A of API Std 1104 may not be used to accept cracks.
§ 192.243   Nondestructive testing.
(a) Nondestructive testing of welds must be performed by any process, other than trepanning, that will clearly indicate defects that may affect the integrity of the weld.
(b) Nondestructive testing of welds must be performed:
(1) In accordance with written procedures; and
(2) By persons who have been trained and qualified in the established procedures and with the equipment employed in testing.
(c) Procedures must be established for the proper interpretation of each nondestructive test of a weld to ensure the acceptability of the weld under § 192.241(c).
(d) When nondestructive testing is required under § 192.241(b), the following percentages of each day's field butt welds, selected at random by the operator, must be nondestructively tested over their entire circumference:
(1) In Class 1 locations, except offshore, at least 10 percent.
(2) In Class 2 locations, at least 15 percent.
(3) In Class 3 and Class 4 locations, at crossings of major or navigable rivers, offshore, and within railroad or public highway rights-of-way, including tunnels, bridges, and overhead road crossings, 100 percent unless impracticable, in which case at least 90 percent. Nondestructive testing must be impracticable for each girth weld not tested.
(4) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent.
(e) Except for a welder or welding operator whose work is isolated from the principal welding activity, a sample of each welder or welding operator's work for each day must be nondestructively tested, when nondestructive testing is required under § 192.241(b).
(f) When nondestructive testing is required under § 192.241(b), each operator must retain, for the life of the pipeline, a record showing by milepost, engineering station, or by geographic feature, the number of girth welds made, the number nondestructively tested, the number rejected, and the disposition of the rejects.
§ 192.245   Repair or removal of defects.
(a) Each weld that is unacceptable under § 192.241(c) must be removed or repaired. Except for welds on an offshore pipeline being installed from a pipeline vessel, a weld must be removed if it has a crack that is more than 8 percent of the weld length.
(b) Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability.
(c) Repair of a crack, or of any defect in a previously repaired area must be in accordance with written weld repair procedures that have been qualified under § 192.225. Repair procedures must provide that the minimum mechanical properties specified for the welding procedure used to make the original weld are met upon completion of the final weld repair.
§ 192.271   Scope.
(a) This subpart prescribes minimum requirements for joining materials in pipelines, other than by welding.
(b) This subpart does not apply to joining during the manufacture of pipe or pipeline components.
§ 192.273   General.
(a) The pipeline must be designed and installed so that each joint will sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping or by anticipated external or internal loading.
(b) Each joint must be made in accordance with written procedures that have been proven by test or experience to produce strong gastight joints.
(c) Each joint must be inspected to insure compliance with this subpart.
§ 192.275   Cast iron pipe.
(a) Each caulked bell and spigot joint in cast iron pipe must be sealed with mechanical leak clamps.
(b) Each mechanical joint in cast iron pipe must have a gasket made of a resilient material as the sealing medium. Each gasket must be suitably confined and retained under compression by a separate gland or follower ring.
(c) Cast iron pipe may not be joined by threaded joints.
(d) Cast iron pipe may not be joined by brazing.
§ 192.277   Ductile iron pipe.
(a) Ductile iron pipe may not be joined by threaded joints.
(b) Ductile iron pipe may not be joined by brazing.
§ 192.279   Copper pipe.
Copper pipe may not be threaded except for copper pipe that is used for joining screw fittings or valves, which may be threaded if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe listed in ASME B36.10M (incorporated by reference, see § 192.7).
§ 192.281   Plastic pipe.
(a) General. A plastic pipe joint that is joined by solvent cement, adhesive, or heat fusion may not be disturbed until it has properly set. Plastic pipe may not be joined by a threaded joint or miter joint.
(b) Solvent cement joints. Each solvent cement joint on plastic pipe must comply with the following:
(1) The mating surfaces of the joint must be clean, dry, and free of material which might be detrimental to the joint.
(2) The solvent cement must conform to ASTM D2564-12 for PVC (incorporated by reference, see § 192.7).
(3) The joint may not be heated or cooled to accelerate the setting of the cement.
(c) Heat-fusion joints. Each heat fusion joint on a PE pipe or component, except for electrofusion joints, must comply with ASTM F2620 (incorporated by reference in § 192.7), or an alternative written procedure that has been demonstrated to provide an equivalent or superior level of safety and has been proven by test or experience to produce strong gastight joints, and the following:
(1) A butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the pipe or component, compresses the heated ends together, and holds the pipe in proper alignment in accordance with the appropriate procedure qualified under § 192.283.
(2) A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the pipe or component, uniformly and simultaneously, to establish the same temperature. The device used must be the same device specified in the operator's joining procedure for socket fusion.
(3) An electrofusion joint must be made using the equipment and techniques prescribed by the fitting manufacturer, or using equipment and techniques shown, by testing joints to the requirements of § 192.283(a)(1)(iii), to be equivalent to or better than the requirements of the fitting manufacturer.
(4) Heat may not be applied with a torch or other open flame.
(d) Adhesive joints. Each adhesive joint on plastic pipe must comply with the following:
(1) The adhesive must conform to ASTM D 2517 (incorporated by reference, see § 192.7).
(2) The materials and adhesive must be compatible with each other.
(e) Mechanical joints. Each compression type mechanical joint on plastic pipe must comply with the following:
(1) The gasket material in the coupling must be compatible with the plastic.
(2) A rigid internal tubular stiffener, other than a split tubular stiffener, must be used in conjunction with the coupling.
(3) All mechanical fittings must meet a listed specification based upon the applicable material.
(4) All mechanical joints or fittings installed after January 22, 2019, must be Category 1 as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than 25% elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard.
§ 192.283   Plastic pipe: Qualifying joining procedures.
(a) Heat fusion, solvent cement, and adhesive joints. Before any written procedure established under § 192.273(b) is used for making plastic pipe joints by a heat fusion, solvent cement, or adhesive method, the procedure must be qualified by subjecting specimen joints that are made according to the procedure to the following tests, as applicable:
(1) The test requirements of—
(i) In the case of thermoplastic pipe, based on the pipe material, the Sustained Pressure Test or the Minimum Hydrostatic Burst Test per the listed specification requirements. Additionally, for electrofusion joints, based on the pipe material, the Tensile Strength Test or the Joint Integrity Test per the listed specification.
(ii) In the case of thermosetting plastic pipe, paragraph 8.5 (Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static Pressure Test) of ASTM D2517- 00 (incorporated by reference, see § 192.7).
(iii) In the case of electrofusion fittings for polyethylene (PE) pipe and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM F1055-98(2006) (incorporated by reference, see § 192.7).
(2) For procedures intended for lateral pipe connections, subject a specimen joint made from pipe sections joined at right angles according to the procedure to a force on the lateral pipe until failure occurs in the specimen. If failure initiates outside the joint area, the procedure qualifies for use.
(3) For procedures intended for non-lateral pipe connections, perform tensile testing in accordance with a listed specification. If the test specimen elongates no less than 25% or failure initiates outside the joint area, the procedure qualifies for use.
(b) Mechanical joints. Before any written procedure established under § 192.273(b) is used for making mechanical plastic pipe joints, the procedure must be qualified in accordance with a listed specification based upon the pipe material.
(c) A copy of each written procedure being used for joining plastic pipe must be available to the persons making and inspecting joints.
§ 192.285   Plastic pipe: Qualifying persons to make joints.
(a) No person may make a plastic pipe joint unless that person has been qualified under the applicable joining procedure by:
(1) Appropriate training or experience in the use of the procedure; and
(2) Making a specimen joint from pipe sections joined according to the procedure that passes the inspection and test set forth in paragraph (b) of this section.
(b) The specimen joint must be:
(1) Visually examined during and after assembly or joining and found to have the same appearance as a joint or photographs of a joint that is acceptable under the procedure; and
(2) In the case of a heat fusion, solvent cement, or adhesive joint:
(i) Tested under any one of the test methods listed under § 192.283(a), and for PE heat fusion joints (except for electrofusion joints) visually inspected in accordance with ASTM F2620 (incorporated by reference, see § 192.7), or a written procedure that has been demonstrated to provide an equivalent or superior level of safety, applicable to the type of joint and material being tested;
(ii) Examined by ultrasonic inspection and found not to contain flaws that would cause failure; or
(iii) Cut into at least 3 longitudinal straps, each of which is:
(A) Visually examined and found not to contain voids or discontinuities on the cut surfaces of the joint area; and
(B) Deformed by bending, torque, or impact, and if failure occurs, it must not initiate in the joint area.
(c) A person must be re-qualified under an applicable procedure once each calendar year at intervals not exceeding 15 months, or after any production joint is found unacceptable by testing under § 192.513.
(d) Each operator shall establish a method to determine that each person making joints in plastic pipelines in the operator's system is qualified in accordance with this section.
(e) For transmission pipe installed after July 1, 2021, records demonstrating each person's plastic pipe joining qualifications at the time of construction in accordance with this section must be retained for a minimum of 5 years following construction.
§ 192.287   Plastic pipe: Inspection of joints.
No person may carry out the inspection of joints in plastic pipes required by §§ 192.273(c) and 192.285(b) unless that person has been qualified by appropriate training or experience in evaluating the acceptability of plastic pipe joints made under the applicable joining procedure.
§ 192.301   Scope.
This subpart prescribes minimum requirements for constructing transmission lines and mains.
§ 192.303   Compliance with specifications or standards.
Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this part.
§ 192.305   Inspection: General.
Each transmission line or main must be inspected to ensure that it is constructed in accordance with this part.
§ 192.307   Inspection of materials.
Each length of pipe and each other component must be visually inspected at the site of installation to ensure that it has not sustained any visually determinable damage that could impair its serviceability.
§ 192.309   Repair of steel pipe.
(a) Each imperfection or damage that impairs the serviceability of a length of steel pipe must be repaired or removed. If a repair is made by grinding, the remaining wall thickness must at least be equal to either:
(1) The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or
(2) The nominal wall thickness required for the design pressure of the pipeline.
(b) Each of the following dents must be removed from steel pipe to be operated at a pressure that produces a hoop stress of 20 percent, or more, of SMYS, unless the dent is repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe:
(1) A dent that contains a stress concentrator such as a scratch, gouge, groove, or arc burn.
(2) A dent that affects the longitudinal weld or a circumferential weld.
(3) In pipe to be operated at a pressure that produces a hoop stress of 40 percent or more of SMYS, a dent that has a depth of:
(i) More than 1/4 inch (6.4 millimeters) in pipe 12 3/4 inches (324 millimeters) or less in outer diameter; or
(ii) More than 2 percent of the nominal pipe diameter in pipe over 12 3/4 inches (324 millimeters) in outer diameter.
(c) Each arc burn on steel pipe to be operated at a pressure that produces a hoop stress of 40 percent, or more, of SMYS must be repaired or removed. If a repair is made by grinding, the arc burn must be completely removed and the remaining wall thickness must be at least equal to either:
(1) The minimum wall thickness required by the tolerances in the specification to which the pipe was manufactured; or
(2) The nominal wall thickness required for the design pressure of the pipeline.
(d) A gouge, groove, arc burn, or dent may not be repaired by insert patching or by pounding out.
(e) Each gouge, groove, arc burn, or dent that is removed from a length of pipe must be removed by cutting out the damaged portion as a cylinder.
§ 192.311   Repair of plastic pipe.
Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired or removed.
§ 192.313   Bends and elbows.
(a) Each field bend in steel pipe, other than a wrinkle bend made in accordance with § 192.315, must comply with the following:
(1) A bend must not impair the serviceability of the pipe.
(2) Each bend must have a smooth contour and be free from buckling, cracks, or any other mechanical damage.
(3) On pipe containing a longitudinal weld, the longitudinal weld must be as near as practicable to the neutral axis of the bend unless:
(i) The bend is made with an internal bending mandrel; or
(ii) The pipe is 12 inches (305 millimeters) or less in outside diameter or has a diameter to wall thickness ratio less than 70.
(b) Each circumferential weld of steel pipe which is located where the stress during bending causes a permanent deformation in the pipe must be nondestructively tested either before or after the bending process.
(c) Wrought-steel welding elbows and transverse segments of these elbows may not be used for changes in direction on steel pipe that is 2 inches (51 millimeters) or more in diameter unless the arc length, as measured along the crotch, is at least 1 inch (25 millimeters).
(d) An operator may not install plastic pipe with a bend radius that is less than the minimum bend radius specified by the manufacturer for the diameter of the pipe being installed.
§ 192.315   Wrinkle bends in steel pipe.
(a) A wrinkle bend may not be made on steel pipe to be operated at a pressure that produces a hoop stress of 30 percent, or more, of SMYS.
(b) Each wrinkle bend on steel pipe must comply with the following:
(1) The bend must not have any sharp kinks.
(2) When measured along the crotch of the bend, the wrinkles must be a distance of at least one pipe diameter.
(3) On pipe 16 inches (406 millimeters) or larger in diameter, the bend may not have a deflection of more than 1 1/2 ° for each wrinkle.
(4) On pipe containing a longitudinal weld the longitudinal seam must be as near as practicable to the neutral axis of the bend.
§ 192.317   Protection from hazards.
(a) The operator must take all practicable steps to protect each transmission line or main from washouts, floods, unstable soil, landslides, or other hazards that may cause the pipeline to move or to sustain abnormal loads. In addition, the operator must take all practicable steps to protect offshore pipelines from damage by mud slides, water currents, hurricanes, ship anchors, and fishing operations.
(b) Each aboveground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades.
(c) Pipelines, including pipe risers, on each platform located offshore or in inland navigable waters must be protected from accidental damage by vessels.
§ 192.319   Installation of pipe in a ditch.
(a) When installed in a ditch, each transmission line that is to be operated at a pressure producing a hoop stress of 20 percent or more of SMYS must be installed so that the pipe fits the ditch so as to minimize stresses and protect the pipe coating from damage.
(b) When a ditch for a transmission line or main is backfilled, it must be backfilled in a manner that:
(1) Provides firm support under the pipe; and
(2) Prevents damage to the pipe and pipe coating from equipment or from the backfill material.
(c) All offshore pipe in water at least 12 feet (3.7 meters) deep but not more than 200 feet (61 meters) deep, as measured from the mean low tide, except pipe in the Gulf of America and its inlets under 15 feet (4.6 meters) of water, must be installed so that the top of the pipe is below the natural bottom unless the pipe is supported by stanchions, held in place by anchors or heavy concrete coating, or protected by an equivalent means. Pipe in the Gulf of America and its inlets under 15 feet (4.6 meters) of water must be installed so that the top of the pipe is 36 inches (914 millimeters) below the seabed for normal excavation or 18 inches (457 millimeters) for rock excavation.
(d) Promptly after a ditch for an onshore steel transmission line is backfilled (if the construction project involves 1,000 feet or more of continuous backfill length along the pipeline), but not later than 6 months after placing the pipeline in service, the operator must perform an assessment to assess any coating damage and ensure integrity of the coating using direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), or other technology that provides comparable information about the integrity of the coating. Coating surveys must be conducted, except in locations where effective coating surveys are precluded by geographical, technical, or safety reasons.
(e) An operator must notify PHMSA in accordance with § 192.18 at least 90 days in advance of using other technology to assess integrity of the coating under paragraph (d) of this section.
(f) An operator of an onshore steel transmission pipeline must develop a remedial action plan and apply for any necessary permits within 6 months of completing the assessment that identified the deficiency. An operator must repair any coating damage classified as severe (voltage drop greater than 60 percent for DCVG or 70 dBµV for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by reference, see § 192.7) within 6 months of the assessment, or as soon as practicable after obtaining necessary permits, not to exceed 6 months after the receipt of permits.
(g) An operator of an onshore steel transmission pipeline must make and retain for the life of the pipeline records documenting the coating assessment findings and remedial actions performed under paragraphs (d) through (f) of this section.
§ 192.321   Installation of plastic pipe.
(a) Plastic pipe must be installed below ground level except as provided in paragraphs (g), (h), and (i) of this section.
(b) Plastic pipe that is installed in a vault or any other below grade enclosure must be completely encased in gas-tight metal pipe and fittings that are adequately protected from corrosion.
(c) Plastic pipe must be installed so as to minimize shear or tensile stresses.
(d) Plastic pipe must have a minimum wall thickness in accordance with § 192.121.
(e) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means.
(f) Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. Plastic pipe that is being encased must be protected from damage at all entrance and all exit points of the casing. The leading end of the plastic must be closed before insertion.
(g) Uncased plastic pipe may be temporarily installed above ground level under the following conditions:
(1) The operator must be able to demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer's recommended maximum period of exposure or 2 years, whichever is less.
(2) The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage.
(3) The pipe adequately resists exposure to ultraviolet light and high and low temperatures.
(h) Plastic pipe may be installed on bridges provided that it is:
(1) Installed with protection from mechanical damage, such as installation in a metallic casing;
(2) Protected from ultraviolet radiation; and
(3) Not allowed to exceed the pipe temperature limits specified in § 192.121.
(i) Plastic mains may terminate above ground level provided they comply with the following:
(1) The above-ground level part of the plastic main is protected against deterioration and external damage.
(2) The plastic main is not used to support external loads.
(3) Installations of risers at regulator stations must meet the design requirements of § 192.204.
§ 192.323   Casing.
Each casing used on a transmission line or main under a railroad or highway must comply with the following:
(a) The casing must be designed to withstand the superimposed loads.
(b) If there is a possibility of water entering the casing, the ends must be sealed.
(c) If the ends of an unvented casing are sealed and the sealing is strong enough to retain the maximum allowable operating pressure of the pipe, the casing must be designed to hold this pressure at a stress level of not more than 72 percent of SMYS.
(d) If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing.
§ 192.325   Underground clearance.
(a) Each transmission line must be installed with at least 12 inches (305 millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure.
(b) Each main must be installed with enough clearance from any other underground structure to allow proper maintenance and to protect against damage that might result from proximity to other structures.
(c) In addition to meeting the requirements of paragraph (a) or (b) of this section, each plastic transmission line or main must be installed with sufficient clearance, or must be insulated, from any source of heat so as to prevent the heat from impairing the serviceability of the pipe.
(d) Each pipe-type or bottle-type holder must be installed with a minimum clearance from any other holder as prescribed in § 192.175(b).
§ 192.327   Cover.
(a) Except as provided in paragraphs (c), (e), (f), and (g) of this section, each buried transmission line must be installed with a minimum cover as follows:
(b) Except as provided in paragraphs (c) and (d) of this section, each buried main must be installed with at least 24 inches (610 millimeters) of cover.
(c) Where an underground structure prevents the installation of a transmission line or main with the minimum cover, the transmission line or main may be installed with less cover if it is provided with additional protection to withstand anticipated external loads.
(d) A main may be installed with less than 24 inches (610 millimeters) of cover if the law of the State or municipality:
(1) Establishes a minimum cover of less than 24 inches (610 millimeters);
(2) Requires that mains be installed in a common trench with other utility lines; and
(3) Provides adequately for prevention of damage to the pipe by external forces.
(e) Except as provided in paragraph (c) of this section, all pipe installed in a navigable river, stream, or harbor must be installed with a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches (610 millimeters) in consolidated rock between the top of the pipe and the underwater natural bottom (as determined by recognized and generally accepted practices).
(f) All pipe installed offshore, except in the Gulf of America and its inlets, under water not more than 200 feet (60 meters) deep, as measured from the mean low tide, must be installed as follows:
(1) Except as provided in paragraph (c) of this section, pipe under water less than 12 feet (3.66 meters) deep, must be installed with a minimum cover of 36 inches (914 millimeters) in soil or 18 inches (457 millimeters) in consolidated rock between the top of the pipe and the natural bottom.
(2) Pipe under water at least 12 feet (3.66 meters) deep must be installed so that the top of the pipe is below the natural bottom, unless the pipe is supported by stanchions, held in place by anchors or heavy concrete coating, or protected by an equivalent means.
(g) All pipelines installed under water in the Gulf of America and its inlets, as defined in § 192.3, must be installed in accordance with § 192.612(b)(3).
§ 192.328   Additional construction requirements for steel pipe using alternative maximum allowable operating pressure.
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure calculated under § 192.620, a segment must meet the following additional construction requirements. Records must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
§ 192.329   Installation of plastic pipelines by trenchless excavation.
Plastic pipelines installed by trenchless excavation must comply with the following:
(a) Each operator must take practicable steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and/or structures at the time of installation.
(b) For each pipeline section, plastic pipe and components that are pulled through the ground must use a weak link, as defined by § 192.3, to ensure the pipeline will not be damaged by any excessive forces during the pulling process.
§ 192.351   Scope.
This subpart prescribes minimum requirements for installing customer meters, service regulators, service lines, service line valves, and service line connections to mains.
§ 192.353   Customer meters and regulators: Location.
(a) Each meter and service regulator, whether inside or outside a building, must be installed in a readily accessible location and be protected from corrosion and other damage, including, if installed outside a building, vehicular damage that may be anticipated. However, the upstream regulator in a series may be buried.
(b) Each service regulator installed within a building must be located as near as practical to the point of service line entrance.
(c) Each meter installed within a building must be located in a ventilated place and not less than 3 feet (914 millimeters) from any source of ignition or any source of heat which might damage the meter.
(d) Where feasible, the upstream regulator in a series must be located outside the building, unless it is located in a separate metering or regulating building.
§ 192.355   Customer meters and regulators: Protection from damage.
(a) Protection from vacuum or back pressure. If the customer's equipment might create either a vacuum or a back pressure, a device must be installed to protect the system.
(b) Service regulator vents and relief vents. Service regulator vents and relief vents must terminate outdoors, and the outdoor terminal must—
(1) Be rain and insect resistant;
(2) Be located at a place where gas from the vent can escape freely into the atmosphere and away from any opening into the building; and
(3) Be protected from damage caused by submergence in areas where flooding may occur.
(c) Pits and vaults. Each pit or vault that houses a customer meter or regulator at a place where vehicular traffic is anticipated, must be able to support that traffic.
§ 192.357   Customer meters and regulators: Installation.
(a) Each meter and each regulator must be installed so as to minimize anticipated stresses upon the connecting piping and the meter.
(b) When close all-thread nipples are used, the wall thickness remaining after the threads are cut must meet the minimum wall thickness requirements of this part.
(c) Connections made of lead or other easily damaged material may not be used in the installation of meters or regulators.
(d) Each regulator that might release gas in its operation must be vented to the outside atmosphere.
§ 192.359   Customer meter installations: Operating pressure.
(a) A meter may not be used at a pressure that is more than 67 percent of the manufacturer's shell test pressure.
(b) Each newly installed meter manufactured after November 12, 1970, must have been tested to a minimum of 10 p.s.i. (69 kPa) gage.
(c) A rebuilt or repaired tinned steel case meter may not be used at a pressure that is more than 50 percent of the pressure used to test the meter after rebuilding or repairing.
§ 192.361   Service lines: Installation.
(a) Depth. Each buried service line must be installed with at least 12 inches (305 millimeters) of cover in private property and at least 18 inches (457 millimeters) of cover in streets and roads. However, where an underground structure prevents installation at those depths, the service line must be able to withstand any anticipated external load.
(b) Support and backfill. Each service line must be properly supported on undisturbed or well-compacted soil, and material used for backfill must be free of materials that could damage the pipe or its coating.
(c) Grading for drainage. Where condensate in the gas might cause interruption in the gas supply to the customer, the service line must be graded so as to drain into the main or into drips at the low points in the service line.
(d) Protection against piping strain and external loading. Each service line must be installed so as to minimize anticipated piping strain and external loading.
(e) Installation of service lines into buildings. Each underground service line installed below grade through the outer foundation wall of a building must:
(1) In the case of a metal service line, be protected against corrosion;
(2) In the case of a plastic service line, be protected from shearing action and backfill settlement; and
(3) Be sealed at the foundation wall to prevent leakage into the building.
(f) Installation of service lines under buildings. Where an underground service line is installed under a building:
(1) It must be encased in a gas tight conduit;
(2) The conduit and the service line must, if the service line supplies the building it underlies, extend into a normally usable and accessible part of the building; and
(3) The space between the conduit and the service line must be sealed to prevent gas leakage into the building and, if the conduit is sealed at both ends, a vent line from the annular space must extend to a point where gas would not be a hazard, and extend above grade, terminating in a rain and insect resistant fitting.
(g) Locating underground service lines. Each underground nonmetallic service line that is not encased must have a means of locating the pipe that complies with § 192.321(e).
§ 192.363   Service lines: Valve requirements.
(a) Each service line must have a service-line valve that meets the applicable requirements of subparts B and D of this part. A valve incorporated in a meter bar, that allows the meter to be bypassed, may not be used as a service-line valve.
(b) A soft seat service line valve may not be used if its ability to control the flow of gas could be adversely affected by exposure to anticipated heat.
(c) Each service-line valve on a high-pressure service line, installed above ground or in an area where the blowing of gas would be hazardous, must be designed and constructed to minimize the possibility of the removal of the core of the valve with other than specialized tools.
§ 192.365   Service lines: Location of valves.
(a) Relation to regulator or meter. Each service-line valve must be installed upstream of the regulator or, if there is no regulator, upstream of the meter.
(b) Outside valves. Each service line must have a shut-off valve in a readily accessible location that, if feasible, is outside of the building.
(c) Underground valves. Each underground service-line valve must be located in a covered durable curb box or standpipe that allows ready operation of the valve and is supported independently of the service lines.
§ 192.367   Service lines: General requirements for connections to main piping.
(a) Location. Each service line connection to a main must be located at the top of the main or, if that is not practical, at the side of the main, unless a suitable protective device is installed to minimize the possibility of dust and moisture being carried from the main into the service line.
(b) Compression-type connection to main. Each compression-type service line to main connection must:
(1) Be designed and installed to effectively sustain the longitudinal pull-out or thrust forces caused by contraction or expansion of the piping, or by anticipated external or internal loading;
(2) If gaskets are used in connecting the service line to the main connection fitting, have gaskets that are compatible with the kind of gas in the system; and
(3) If used on pipelines comprised of plastic, be a Category 1 connection as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than 25% elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard.
§ 192.369   Service lines: Connections to cast iron or ductile iron mains.
(a) Each service line connected to a cast iron or ductile iron main must be connected by a mechanical clamp, by drilling and tapping the main, or by another method meeting the requirements of § 192.273.
(b) If a threaded tap is being inserted, the requirements of § 192.151 (b) and (c) must also be met.
§ 192.371   Service lines: Steel.
Each steel service line to be operated at less than 100 p.s.i. (689 kPa) gage must be constructed of pipe designed for a minimum of 100 p.s.i. (689 kPa) gage.
§ 192.373   Service lines: Cast iron and ductile iron.
(a) Cast or ductile iron pipe less than 6 inches (152 millimeters) in diameter may not be installed for service lines.
(b) If cast iron pipe or ductile iron pipe is installed for use as a service line, the part of the service line which extends through the building wall must be of steel pipe.
(c) A cast iron or ductile iron service line may not be installed in unstable soil or under a building.
§ 192.375   Service lines: Plastic.
(a) Each plastic service line outside a building must be installed below ground level, except that—
(1) It may be installed in accordance with § 192.321(g); and
(2) It may terminate above ground level and outside the building, if—
(i) The above ground level part of the plastic service line is protected against deterioration and external damage;
(ii) The plastic service line is not used to support external loads; and
(iii) The riser portion of the service line meets the design requirements of § 192.204.
(b) Each plastic service line inside a building must be protected against external damage.
§ 192.376   Installation of plastic service lines by trenchless excavation.
Plastic service lines installed by trenchless excavation must comply with the following:
(a) Each operator shall take practicable steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and structures at the time of installation.
(b) For each pipeline section, plastic pipe and components that are pulled through the ground must use a weak link, as defined by § 192.3, to ensure the pipeline will not be damaged by any excessive forces during the pulling process.
§ 192.377   Service lines: Copper.
Each copper service line installed within a building must be protected against external damage.
§ 192.379   New service lines not in use.
Each service line that is not placed in service upon completion of installation must comply with one of the following until the customer is supplied with gas:
(a) The valve that is closed to prevent the flow of gas to the customer must be provided with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator.
(b) A mechanical device or fitting that will prevent the flow of gas must be installed in the service line or in the meter assembly.
(c) The customer's piping must be physically disconnected from the gas supply and the open pipe ends sealed.
§ 192.381   Service lines: Excess flow valve performance standards.
(a) Excess flow valves (EFVs) to be used on service lines that operate continuously throughout the year at a pressure not less than 10 p.s.i. (69 kPa) gage must be manufactured and tested by the manufacturer according to an industry specification, or the manufacturer's written specification, to ensure that each valve will:
(1) Function properly up to the maximum operating pressure at which the valve is rated;
(2) Function properly at all temperatures reasonably expected in the operating environment of the service line;
(3) At 10 p.s.i. (69 kPa) gage:
(i) Close at, or not more than 50 percent above, the rated closure flow rate specified by the manufacturer; and
(ii) Upon closure, reduce gas flow—
(A) For an excess flow valve designed to allow pressure to equalize across the valve, to no more than 5 percent of the manufacturer's specified closure flow rate, up to a maximum of 20 cubic feet per hour (0.57 cubic meters per hour); or
(B) For an excess flow valve designed to prevent equalization of pressure across the valve, to no more than 0.4 cubic feet per hour (.01 cubic meters per hour); and
(4) Not close when the pressure is less than the manufacturer's minimum specified operating pressure and the flow rate is below the manufacturer's minimum specified closure flow rate.
(b) An excess flow valve must meet the applicable requirements of Subparts B and D of this part.
(c) An operator must mark or otherwise identify the presence of an excess flow valve in the service line.
(d) An operator shall locate an excess flow valve as near as practical to the fitting connecting the service line to its source of gas supply.
(e) An operator should not install an excess flow valve on a service line where the operator has prior experience with contaminants in the gas stream, where these contaminants could be expected to cause the excess flow valve to malfunction or where the excess flow valve would interfere with necessary operation and maintenance activities on the service, such as blowing liquids from the line.
§ 192.383   Excess flow valve installation.
(a) Definitions. As used in this section:
Branched service line means a gas service line that begins at the existing service line or is installed concurrently with the primary service line but serves a separate residence.
Replaced service line means a gas service line where the fitting that connects the service line to the main is replaced or the piping connected to this fitting is replaced.
Service line serving single-family residence means a gas service line that begins at the fitting that connects the service line to the main and serves only one single-family residence (SFR).
(b) Installation required. An EFV installation must comply with the performance standards in § 192.381. After April 14, 2017, each operator must install an EFV on any new or replaced service line serving the following types of services before the line is activated:
(1) A single service line to one SFR;
(2) A branched service line to a SFR installed concurrently with the primary SFR service line ( i.e., a single EFV may be installed to protect both service lines);
(3) A branched service line to a SFR installed off a previously installed SFR service line that does not contain an EFV;
(4) Multifamily residences with known customer loads not exceeding 1,000 SCFH per service, at time of service installation based on installed meter capacity, and
(5) A single, small commercial customer served by a single service line with a known customer load not exceeding 1,000 SCFH, at the time of meter installation, based on installed meter capacity.
(c) Exceptions to excess flow valve installation requirement. An operator need not install an excess flow valve if one or more of the following conditions are present:
(1) The service line does not operate at a pressure of 10 psig or greater throughout the year;
(2) The operator has prior experience with contaminants in the gas stream that could interfere with the EFV's operation or cause loss of service to a customer;
(3) An EFV could interfere with necessary operation or maintenance activities, such as blowing liquids from the line; or
(4) An EFV meeting the performance standards in § 192.381 is not commercially available to the operator.
(d) Customer's right to request an EFV. Existing service line customers who desire an EFV on service lines not exceeding 1,000 SCFH and who do not qualify for one of the exceptions in paragraph (c) of this section may request an EFV to be installed on their service lines. If an eligible service line customer requests an EFV installation, an operator must install the EFV at a mutually agreeable date. The operator's rate-setter determines how and to whom the costs of the requested EFVs are distributed.
(e) Operator notification of customers concerning EFV installation. Operators must notify customers of their right to request an EFV in the following manner:
(1) Except as specified in paragraphs (c) and (e)(5) of this section, each operator must provide written or electronic notification to customers of their right to request the installation of an EFV. Electronic notification can include emails, Web site postings, and e-billing notices.
(2) The notification must include an explanation for the service line customer of the potential safety benefits that may be derived from installing an EFV. The explanation must include information that an EFV is designed to shut off the flow of natural gas automatically if the service line breaks.
(3) The notification must include a description of EFV installation and replacement costs. The notice must alert the customer that the costs for maintaining and replacing an EFV may later be incurred, and what those costs will be to the extent known.
(4) The notification must indicate that if a service line customer requests installation of an EFV and the load does not exceed 1,000 SCFH and the conditions of paragraph (c) are not present, the operator must install an EFV at a mutually agreeable date.
(5) Operators of master-meter systems and liquefied petroleum gas (LPG) operators with fewer than 100 customers may continuously post a general notification in a prominent location frequented by customers.
(f) Operator evidence of customer notification. An operator must make a copy of the notice or notices currently in use available during PHMSA inspections or State inspections conducted under a pipeline safety program certified or approved by PHMSA under 49 U.S.C. 60105 or 60106.
(g) Reporting. Except for operators of master-meter systems and LPG operators with fewer than 100 customers, each operator must report the EFV measures detailed in the annual report required by § 191.11.
§ 192.385   Manual service line shut-off valve installation.
(a) Definitions. As used in this section:
Manual service line shut-off valve means a curb valve or other manually operated valve located near the service line that is safely accessible to operator personnel or other personnel authorized by the operator to manually shut off gas flow to the service line, if needed.
(b) Installation requirement. The operator must install either a manual service line shut-off valve or, if possible, based on sound engineering analysis and availability, an EFV for any new or replaced service line with installed meter capacity exceeding 1,000 SCFH.
(c) Accessibility and maintenance. Manual service line shut-off valves for any new or replaced service line must be installed in such a way as to allow accessibility during emergencies. Manual service shut-off valves installed under this section are subject to regular scheduled maintenance, as documented by the operator and consistent with the valve manufacturer's specification.
§ 192.451   Scope.
(a) This subpart prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion.
(b) [Reserved]
§ 192.452   How does this subpart apply to converted pipelines and regulated onshore gathering pipelines?
(a) Converted pipelines. Notwithstanding the date the pipeline was installed or any earlier deadlines for compliance, each pipeline which qualifies for use under this part in accordance with § 192.14 must meet the requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, and all other applicable requirements within 1 year after the pipeline is readied for service. However, the requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply if the pipeline substantially meets those requirements before it is readied for service or it is a segment which is replaced, relocated, or substantially altered.
(b) Type A and B onshore gathering lines. For any Type A or Type B regulated onshore gathering line under § 192.9 existing on April 14, 2006, that was not previously subject to this part, and for any onshore gathering line that becomes a regulated onshore gathering line under § 192.9 after April 14, 2006, because of a change in class location or increase in dwelling density:
(1) The requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, apply to the gathering line regardless of the date the pipeline was actually installed; and
(2) The requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply only if the pipeline substantially meets those requirements.
(c) Type C onshore regulated gathering lines. For any Type C onshore regulated gathering pipeline under § 192.9 existing on May 16, 2022, that was not previously subject to this part, and for any Type C onshore gas gathering pipeline that becomes subject to this subpart after May 16, 2022, because of an increase in MAOP, change in class location, or presence of a building intended for human occupancy or other impacted site:
(1) The requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, apply to the gathering line regardless of the date the pipeline was actually installed; and
(2) The requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply only if the pipeline substantially meets those requirements.
(d) Regulated onshore gathering lines generally. Any gathering line that is subject to this subpart per § 192.9 at the time of construction must meet the requirements of this subpart applicable to pipelines installed after July 31, 1971.
§ 192.453   General.
The corrosion control procedures required by § 192.605(b)(2), including those for the design, installation, operation, and maintenance of cathodic protection systems, must be carried out by, or under the direction of, a person qualified in pipeline corrosion control methods.
§ 192.455   External corrosion control: Buried or submerged pipelines installed after July 31, 1971.
(a) Except as provided in paragraphs (b), (c), (f), and (g) of this section, each buried or submerged pipeline installed after July 31, 1971, must be protected against external corrosion, including the following:
(1) It must have an external protective coating meeting the requirements of § 192.461.
(2) It must have a cathodic protection system designed to protect the pipeline in accordance with this subpart, installed and placed in operation within 1 year after completion of construction.
(b) An operator need not comply with paragraph (a) of this section, if the operator can demonstrate by tests, investigation, or experience in the area of application, including, as a minimum, soil resistivity measurements and tests for corrosion accelerating bacteria, that a corrosive environment does not exist. However, within 6 months after an installation made pursuant to the preceding sentence, the operator shall conduct tests, including pipe-to-soil potential measurements with respect to either a continuous reference electrode or an electrode using close spacing, not to exceed 20 feet (6 meters), and soil resistivity measurements at potential profile peak locations, to adequately evaluate the potential profile along the entire pipeline. If the tests made indicate that a corrosive condition exists, the pipeline must be cathodically protected in accordance with paragraph (a)(2) of this section.
(c) An operator need not comply with paragraph (a) of this section, if the operator can demonstrate by tests, investigation, or experience that—
(1) For a copper pipeline, a corrosive environment does not exist; or
(2) For a temporary pipeline with an operating period of service not to exceed 5 years beyond installation, corrosion during the 5-year period of service of the pipeline will not be detrimental to public safety.
(d) Notwithstanding the provisions of paragraph (b) or (c) of this section, if a pipeline is externally coated, it must be cathodically protected in accordance with paragraph (a)(2) of this section.
(e) Aluminum may not be installed in a buried or submerged pipeline if that aluminum is exposed to an environment with a natural pH in excess of 8, unless tests or experience indicate its suitability in the particular environment involved.
(f) This section does not apply to electrically isolated, metal alloy fittings in plastic pipelines, if:
(1) For the size fitting to be used, an operator can show by test, investigation, or experience in the area of application that adequate corrosion control is provided by the alloy composition; and
(2) The fitting is designed to prevent leakage caused by localized corrosion pitting.
(g) Electrically isolated metal alloy fittings installed after January 22, 2019, that do not meet the requirements of paragraph (f) must be cathodically protected, and must be maintained in accordance with the operator's integrity management plan.